Power generation and co2 capture with turbines in series

ABSTRACT

In various aspects, a method for producing electricity by operating two or more turbines in series is provided. The method can include introducing, at least part of, the exhaust from an upstream turbine into a combustion chamber of a downstream turbine. In one aspect, exhaust from the upstream turbine is introduced into the downstream turbine&#39;s combustion chamber via the downstream turbine&#39;s compression chamber.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of provisional U.S. Serial Nos. 61/884,376, 61/884,545, 61/884,565, 61/884,586, 61/884,605, and 61/884,635, all filed on Sep. 30, 2013, each of which is incorporated by reference herein in its entirety. This application further claims the benefit of provisional U.S. Ser. No. 61/889,757, filed on Oct. 11, 2013, which is incorporated by reference herein in its entirety. This application further claims priority as continuations-in-part of non-provisional U.S. Ser. Nos. 14/197,397, 14/197,430, 14/197,551, 14/197,613, 14/207,686, 14/207,687, 14/207,690, 14/207,691, 14/207,693, 14/207,697, 14/207,698, 14/207,699, 14/207,706, 14/207,708, 14/207,710, 14/207,711, 14/207,712, 14/207,714, 14/207,721, 14/207,726, and 14/207,728, all filed on Mar. 13, 2014, and to U.S. Ser. Nos. 14/315,419, 14/315,439, 14/315,479, 14/315,507, and 14/315,527, all filed on Jun. 26, 2014, each of which is incorporated by reference herein in its entirety.

This application is further related to two other co-pending U.S. applications, filed on even date herewith, and identified by the following Attorney Docket numbers and titles: 2013EM243-US entitled “Integrated Power Generation and Chemical Production using Solid Oxide Fuel Cells”; and 2014EM245-US entitled “Cathode Combustion for Enhanced Fuel Cell Syngas Production”. Each of these co-pending U.S. applications is hereby incorporated by reference herein in its entirety.

FIELD OF THE INVENTION

In various aspects, the invention is related to power production processes using gas turbines integrated with fuel cells.

BACKGROUND OF THE INVENTION

Gas turbines are commonly used for the generation of electrical power due to their compact size, high efficiency, and low capital cost. Gas turbines may be deployed in a combined cycle system that pairs a combustion turbine generator (“CTG”) with a heat recovery steam generation (“HRSG”). In a combined cycle system, the CTG produces electricity and then the exhaust from the CTG is used by the HRSG to generate steam that can be introduced to a stream turbine to generate additional electricity.

The CTG can use a compression chamber to compress air to a high pressure and temperature. The compressed air is then introduced into a compression chamber where a constant pressure combustion of the fuel occurs. The hot exhaust is then expanded across a turbine to let down the pressure and decrease the temperature. The work of the CTG is to spin an axle which is connected to an electrical generator, which produces alternating current. The hot exhaust from the gas turbine can be used to create steam in the RSG, and this steam can be used to spin a steam turbine generator, or STG, creating more electricity.

Molten carbonate fuel cells utilize hydrogen and/or other fuels to generate electricity. The hydrogen may be provided by reforming methane or other reformable fuels in a steam reformer that is upstream of the fuel cell or within the fuel cell. Reformable fuels can encompass hydrocarbonaceous materials that can be reacted with steam and/or oxygen at elevated temperature and/or pressure to produce a gaseous product that comprises hydrogen. Alternatively or additionally, fuel can be reformed in the anode cell in a molten carbonate fuel cell, which can be operated to create conditions that are suitable for reforming fuels in the anode. Alternately or additionally, the reforming can occur both externally and internally to the fuel cell.

Traditionally, molten carbonate fuel cells are operated to maximize electricity production per unit of fuel input, which may be referred to as the fuel cell's electrical efficiency. This maximization can be based on the fuel cell alone or in conjunction with another power generation system. In order to achieve increased electrical production and to manage the heat generation, fuel utilization within a fuel cell is typically maintained at 70% to 75%.

U.S. Patent Application Publication No. 2011/0111315 describes a system and process for operating fuel cell systems with substantial hydrogen content in the anode inlet stream. The technology in the '315 publication is concerned with providing enough fuel in the anode inlet so that sufficient fuel remains for the oxidation reaction as the fuel approaches the anode exit. To ensure adequate fuel, the '315 publication provides fuel with a high concentration of H₂. The H₂ not utilized in the oxidation reaction is recycled to the anode for use in the next pass. On a single pass basis, the H₂ utilization may range from 10% to 30%. The '315 reference does not describe significant reforming within the anode, instead relying primarily on external reforming.

U.S. Patent Application Publication No. 2005/0123810 describes a system and method for co-production of hydrogen and electrical energy. The co-production system comprises a fuel cell and a separation unit, which is configured to receive the anode exhaust stream and separate hydrogen. A portion of the anode exhaust is also recycled to the anode inlet. The operating ranges given in the '810 publication appear to be based on a solid oxide fuel cell. Molten carbonate fuel cells are described as an alternative.

U.S. Patent Application Publication No. 2003/0008183 describes a system and method for co-production of hydrogen and electrical power. A fuel cell is mentioned as a general type of chemical converter for converting a hydrocarbon-type fuel to hydrogen. The fuel cell system also includes an external reformer and a high temperature fuel cell. An embodiment of the fuel cell system is described that has an electrical efficiency of about 45% and a chemical production rate of about 25% resulting in a system coproduction efficiency of about 70%. The '183 publication does not appear to describe the electrical efficiency of the fuel cell in isolation from the system.

An article in the Journal of Fuel Cell Science and Technology (G. Manzolini et. al., J. Fuel Cell Sci. and Tech., Vol. 9, February 2012) describes a power generation system that combines a combustion power generator with molten carbonate fuel cells. Various arrangements of fuel cells and operating parameters are described. The combustion output from the combustion generator is used in part as the input for the cathode of the fuel cell. One goal of the simulations in the Manzolini article is to use the MCFC to separate CO₂ from the power generator's exhaust. The simulation described in the Manzolini article establishes a maximum outlet temperature of 660° C. and notes that the inlet temperature must be sufficiently cooler to account for the temperature increase across the fuel cell. The electrical efficiency (i.e., electricity generated/fuel input) for the MCFC fuel cell in a base model case is 50%. The electrical efficiency in a test model case, which is optimized for CO₂ sequestration, is also 50%.

An article by Desideri et al. (Intl. J. of Hydrogen Energy, Vol. 37, 2012) describes a method for modeling the performance of a power generation system using a fuel cell for CO₂ separation. Recirculation of anode exhaust to the anode inlet and the cathode exhaust to the cathode inlet are used to improve the performance of the fuel cell. The model parameters describe an MCFC electrical efficiency of 50.3%.

SUMMARY OF THE INVENTION

In an aspect, a method for producing electricity by operating two or more turbines in series is provided. The method can include introducing, at least part of, the exhaust from an upstream turbine into a combustion chamber of a downstream turbine. In one aspect, exhaust from the upstream turbine is introduced into the downstream turbine's combustion chamber via the downstream turbine's compression chamber. Operating two or more turbines in series can allow the exhaust from the upstream turbine to be a source of oxygen for combustion in the downstream turbine(s). Running two or more turbines in series can produce a final exhaust stream with a higher concentration of CO₂ and a lower concentration of O₂ than is produced by individual or parallel operation of combustion turbines. In general, the higher concentration of CO₂ can allow for the CO₂ to be removed from the exhaust more efficiently.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 schematically shows an example of a configuration for molten carbonate fuel cells and associated reforming and separation stages.

FIG. 2 schematically shows another example of a configuration for molten carbonate fuel cells and associated reforming and separation stages.

FIG. 3 schematically shows an example of the operation of a molten carbonate fuel cell.

FIG. 4 schematically shows an example of a serial turbine system and molten carbonate fuel cell for generating electricity based on combustion of a carbon-based fuel.

FIG. 5 schematically shows an example of a serial turbine system for generating electricity based on combustion of a carbon-based fuel.

FIG. 6 shows results of simulations of a serial turbine system for generating electricity.

FIG. 7 schematically shows an example of a single turbine system for generating electricity based on combustion of a carbon-based fuel.

FIG. 8 shows results of simulations of a system for generating electricity.

FIG. 9 schematically shows an example of a parallel turbine system for generating electricity based on combustion of a carbon-based fuel.

FIG. 10 shows results of simulations of a system for generating electricity.

FIG. 11 schematically shows an example of a combined cycle system with exhaust gas recycle for generating electricity based on combustion of a carbon-based fuel.

FIG. 12 schematically shows an example of a combined cycle system with exhaust gas recycle for generating electricity based on combustion of a carbon-based fuel.

FIG. 13 shows results of simulations of a system for generating electricity.

DETAILED DESCRIPTION OF THE EMBODIMENTS Overview

In an aspect, a method for producing electricity by operating two or more combustion turbines in series is provided. The method includes introducing, at least part of, the exhaust from an upstream turbine into a combustion chamber of a downstream turbine. In one aspect, exhaust from the upstream turbine is introduced into the downstream turbine's combustion chamber via the downstream turbine's compression chamber. Operating two or more turbines in series allows the exhaust from the upstream turbine to be a source of oxygen for combustion in the downstream turbine(s). Running two or more turbines in series can produce a final exhaust stream with a higher concentration of CO₂ and a lower concentration of O₂ than is produced by individual or parallel operation of combustion turbines. In general, the higher concentration of CO₂ allows for the CO₂ to be removed from the exhaust more efficiently.

Serial Operation of Combustion Turbines

In various aspects, two or more combustion turbines are operated in series to produce electricity. As used herein, serial operation comprises introducing a substantial portion of CO₂ from an upstream turbine's exhaust into a combustion chamber of a downstream turbine. The exhaust may be introduced into the combustion chamber of the downstream turbine via downstream turbine's compression chamber. In one aspect, greater than about 50% of the CO₂ in an upstream turbine's exhaust is introduced into a downstream turbine's combustion chamber. For example, the amount of CO₂ introduced into a downstream turbine's combustion chamber from the upstream turbine exhaust can be greater than about 50% of the CO₂ in the upstream turbine exhaust, or greater than about 60%, or greater than about 70%, or greater than about 80%, or greater than about 90%, or greater than about 95%, or greater than about 99%, or greater than about 99.5%, or about 100%.

In one aspect, greater than about 50% of the O₂ in an upstream turbine's exhaust is introduced into a downstream turbine's combustion chamber. For example, the amount of O₂ introduced into a downstream turbine's combustion chamber from the upstream turbine exhaust can be greater than about 50% of the O₂ in the upstream turbine exhaust, or greater than about 60%, or greater than about 70%, or greater than about 80%, or greater than about 90%, or greater than about 95%, or greater than about 99%, or greater than about 99.5%.

In one aspect, oxygen can be added to an upstream turbine's exhaust prior to the exhaust being introduced into a combustion chamber of a downstream turbine. The oxygen may be added by introducing air into the exhaust. Air may be added to facilitate a desired turbine performance, for example, to enable almost complete combustion of fuel introduced into the combustion chamber or reduction of NOx production. In one aspect, the ratio of exhaust gas to air is between about 1:1 and about 100:1. For example, the ratio of exhaust gas to air can be about 10:1, or about 25:1, or about 50:1, or about 75:1, or about 90:1. In one aspect, the ratio of oxygen provided to the downstream combustion chamber by the exhaust to the amount provided by air is between about 1:1 and about 50:1. For example, the ratio of oxygen provided to the downstream combustion chamber by the exhaust to the amount provided by air can be about 5:1, or about 15:1, or about 25:1, or about 35:1, or about 45:1. As such, the oxygen from the upstream turbine's exhaust can comprise greater than about 50% of the oxygen supplied to the downstream turbine's combustion chamber. For example, oxygen from the upstream turbine's exhaust can comprise at least about 50%, or at least about 60%, or at least about 70%, or at least about 75%, or at least about 80%, or at least about 85%, or at least about 90%, or at least about 95%, or up to about 100% of the of the oxygen supplied to the downstream turbine's combustion chamber.

In one aspect the exhaust or flue gas produced by operating two or more combustion turbines in series can have a higher concentration of CO₂ than an is achieved by the operation of a single combustion turbine or multiple combustion turbines operating in parallel. For example, the exhaust gas from a second turbine in series may have a CO₂ concentration that is at least about 6.0 mol %, for example, or at least about 6.5%, or at least about 7.0%, or at least about 7.5%, or at least about 8%, or at least about 8.5%, or at least about 9.0%, or at least about 9.5%, or at least about 10%, or at least about 11%, or at least about 12%, or at least about 15%. This can be in contrast to the CO₂ concentration in the exhaust from the upstream (first) turbine, which can be about 7.5 mol % or less, or about 6.5 mol % or less, or about 5.5 mol % or less, or about 4.5 mol % or less. The increased CO₂ concentration can have multiple benefits, including improved efficiency of some CO₂ removal processes, for example, using and amine scrubber. The higher CO₂ concentration may result in lowered operating cost and lower capital outlay per mole of CO₂ captured. Additionally or alternately, the amount of CO₂ in the exhaust from the upstream or first turbine can be expressed as a ratio relative to the amount of CO₂ in the exhaust from the downstream or second turbine. In various aspects, the amount of CO₂ in the downstream (second) exhaust relative to the amount of CO₂ in the upstream (first) exhaust can be at least about 1.3:1, or at least about 1.4:1, or at least about 1.5:1, or at least about 1.6:1, or at least about 1.7:1, or at least about 1.8:1. For turbines operating a similar type of combustion reaction (e.g., based on a similar fuel), the ratio of CO₂ in the second exhaust to CO₂ in the first exhaust will typically be 2.0:1 or less.

In one aspect the exhaust or flue gas produced by operating two or more combustion turbines in series can have a lower concentration of O₂ than an is achieved by the operation of a single combustion turbine or multiple combustion turbines operating in parallel. For example, the exhaust gas from a second turbine in series may have an O₂ concentration that is at less than about 8.0 molar %, for example less than about 7.0%, or less than about 6%, or less than about 5%, or less than about 4%, or less than about 3.0%, or less than about 2.0%, or less than about 1.5% or less than about 1%, or less than about 0.5%. The reduced oxygen stream can be a valuable input to processes that use an inert gas, for example pressure maintenance of underground gas formations. In one aspect, the desired O₂ level can be achieved by mixing in more or less fresh air with the turbine exhaust feed to a downstream turbine. In an aspect, the desired O₂ level can be achieved by mixing air with the exhaust of a downstream turbine prior to feeding the exhaust gas into a process that uses the O₂ depleted gas. The temperature of the extra air added to adjust the O₂ level can be selected to heat or cool the exhaust gas to a temperature preferred for the downstream process.

In aspects, water may be optionally removed from an upstream turbine's exhaust before the exhaust is introduced into the downstream turbine. Accordingly, in one aspect, the exhaust gas introduced into a second turbine in series may have an H₂O concentration that is at less than about 6.0 molar %, for example less than about 5.0%, or less than about 4%, or less than about 3%, or less than about 2%, or less than about 1.0%, or less than about 0.5%.

FIG. 5 schematically shows an example of an integrated power generation system 500 including two combustion turbines operated in a serial arrangement. Aspects of the invention are not limited to the use of two turbines in series. In various aspects, three or more turbines could be used in series, but for the sake of simplicity two turbines are described in this system 500. In various aspects turbines of the same or different capacity may be arranged in series. For example, the upstream turbine could have a larger capacity than the downstream turbine, the upstream turbine could have a smaller capacity than the downstream turbine, or the turbines could have the same capacity. In FIG. 5, exhaust 592 from the first turbine 501 is introduced into the second turbine 541 as a source of oxygen for the combustion of fuel.

The first turbine 501 can include a compressor 502, a shaft 504, an expander 506, and a combustion zone 515. An oxygen source 511 (such as air and/or oxygen-enriched air) can be compressed and heated in compressor 502 prior to entering 513 combustion zone 515. A fuel 512, such as CH₄, can be delivered to the combustion zone 515. The fuel and oxidant can be reacted in zone 515 and optionally but preferably passed 516 through expander 506 to turn shaft 504, which is connected to an electric generator to generate electric power. The exhaust gas 592 can be used as the input for a heat recovery and steam generator system 590, which can, for example, generate steam 594 for steam turbines 595, which generates additional electricity.

Stream 520 comprises water that is removed from the first turbine's exhaust prior to introduction to the second turbine.

The second turbine 541 can include a compressor 542, a shaft 544, an expander 546, and a combustion zone 545. An oxygen source 541 (such as air and/or oxygen-enriched air) can be compressed and heated in compressor 545 prior to entering 553 combustion zone 545. A fuel 552, such as CH₄, can be delivered to the combustion zone 545. The fuel and oxidant can be reacted in zone 545 and optionally but preferably passed 556 through expander 546 to turn shaft 544, which is connected to an electric generator to generate electric power. The exhaust gas 558 can be used as the input for a heat recovery and steam generator system 560, which can, for example, generate steam 562 for steam turbines 595, which generates additional electricity. Optionally, each HRSG 560 and 590 could feed a separate steam turbine instead of the single steam turbine 595 shown.

The flue gas 570 may be introduced into a system that removes CO₂, such as an amine scrubber, prior to release to the atmosphere. In one aspect, the flue gas 570 is introduced into a fuel cell cathode, as shown in FIG. 4.

As an example, simulations were performed using a configuration similar to the system shown in FIG. 5. The mass balance results from the simulations are shown in FIG. 6. General Electric's Frame 9Fb.05 turbine was used as the basis for the simulations. The simulation results shown in FIG. 6 show pound moles per hour and concentrations as a mole fraction percent. For the sake of simplicity, the simulations will be described in terms of mole fraction percent.

The air 511 enters the compressor 502 with substantially no CO₂. The air 511 in the simulations contained about 20.8% oxygen. The fuel 512 fed into the turbine's combustion chamber in the simulations contained about 93% methane. During combustion, the methane in the simulations was combined with O₂ to create CO₂ and water. The simulations were performed to result in complete combustion of methane. The air to methane ratio in the simulations was about 24.6:1.

The first turbine's exhaust 592 in the simulations had a CO₂ concentration of about 4.2% and an O₂ concentration of about 11.7% as it entered the HRSG 590. Thus, the CO₂ concentration in the simulations was increased from approximately 0% to 4.2% and the O₂ concentration decreased from approximately 20.8% to about 11.7%. The nitrogen mostly passed through the combustion chamber unreacted in the simulations, though a small amount of NO_(x) gas was formed.

The HRSG 590 in the simulations cooled the exhaust 592 from 1052° F. to 134° F., but did not otherwise change the composition of the exhaust, which results in cold flue gas 514. The removal of water 520 reduced the concentration of water from about 8.7% to about 0.5%, resulting in exhaust gas 517. Though not simulated in this case, the presence of a duct burner in the HRSG 590 could further increase the concentration of CO₂ and reduce the concentration of oxygen.

The exhaust input 519 into the second turbine 541 in the simulations was generated by combining exhaust gas 517 with additional air 540. The exhaust input 519 comprises about 4.4% CO₂ and about 13.1% O₂. The fuel 552 fed into the turbine's combustion chamber in the simulations was about 93% methane. During combustion, the methane was combined with O₂ to create CO₂ and water. The simulations were performed to have complete combustion of methane. The air to methane ratio was about 24.6:1 in the simulations.

The second turbine's exhaust 558 in the simulations had a CO₂ concentration of about 8.3% and an O₂ concentration of about 4.4% as it entered the HRSG 560. Thus, in the simulations the CO₂ concentration increased from approximately 4.4% to 8.32% and the O₂ concentration decreased from approximately 13.1% to about 4.4%. The nitrogen in the simulations mostly passed through the combustion chamber unreacted, though a small amount of NO_(x) gas was formed. The HRSG 560 in the simulations cooled the exhaust 558 from 1052° F. to 134° F., but did not otherwise change the composition of the exhaust.

Based on the simulations, operating two combustion turbines in sequence allowed for creation of a combustion exhaust stream with almost double the CO₂ concentration of a single combustion turbine. The higher CO₂ content can be beneficial for operation of a subsequent molten carbonate fuel cell. For example, molten carbonate fuel cells can typically be limited in removing CO₂ from a cathode stream, as a CO₂ concentration of at least about 0.3 mol %, or at least about 0.5 mol %, or at least about 0.8 mol %, or at least about 1 mol %, or at least about 1.2 mol %, or at least about 1.5 mol % can be needed to operate the fuel cell in a desired operating regime. If a cathode inlet stream has an input concentration of about 4.5 mol %, reducing the CO₂ concentration to about 1.5 mol % corresponds to transporting about 66% of the CO₂ in the cathode to the anode. By contrast, if a cathode inlet stream has an input concentration of about 7.5 mol %, reducing the CO₂ concentration to about 1.5 mol % corresponds to transporting about 80% of the CO₂ in the cathode to the anode. Thus, using the exhaust from two combustion turbines in series can provide an opportunity for substantially enhanced removal of CO₂ in comparison with removing CO₂ from two individual combustion exhaust streams.

Combustion Turbine Generator with Heat Recovery Steam Generator

FIG. 7 schematically shows an example of an integrated power generation system 700 including a combustion turbine, a heat recovery and steam generator system, and a steam turbine. The system 700 shown in FIG. 7 may be referred to as a “1×1” system, which means that one combustion turbine generator is used to produce electricity, one HRSG is used to produce steam, and that steam drives one steam turbine generator. The system 700 is included herein to illustrate typical characteristics of system exhaust from a single turbine. These characteristics are explained in more detail with reference to simulation results shown in FIG. 8.

In FIG. 7, the turbine can include a compressor 702, a shaft 704, an expander 706, and a combustion zone 715. An oxygen source 711 (such as air and/or oxygen-enriched air) can be compressed and heated in compressor 702 prior to entering 713 combustion zone 715. A fuel 712, such as CH₄, can be delivered to the combustion zone 715. The fuel and oxidant can be reacted in zone 715 and optionally but preferably passed 716 through expander 706 to turn shaft 717, which is connected to an electric generator to generate electric power. The exhaust gas 792 can be used as the input for a heat recovery and steam generator system 790, which can, for example, generate steam 794 for steam turbines 795, which generates additional electricity. Flue gas 796 exits the HRSG 790.

As an example, simulations were performed using a configuration similar to the system shown in FIG. 7. The results from the simulations are shown in FIG. 8. General Electric's Frame 9Fb.05 turbine was used as the basis for the simulations. The simulation results shown in FIG. 8 show pound moles per hour and concentrations as a mole fraction percent. For the sake of simplicity, the simulations will be described in terms of mole fraction percent.

The air 711 entered the compressor 702 in the simulations with substantially no CO₂. The air 711 contained about 20.8% oxygen. The fuel fed into the turbine's combustion chamber in the simulations was about 93% methane. During combustion in the simulations, the methane was combined with O₂ to create CO₂ and water. The simulations were performed to have complete combustion of methane. The air to methane ratio was about 24.6:1 in the simulations shown.

The turbine exhaust 792 in the simulations had a CO₂ concentration of about 4.2% and an O₂ concentration of about 11.7% as it entered the HRSG. Thus, the CO₂ concentration increased from approximately 0% to 4.2% and the O₂ concentration decreased from approximately 20.8% to about 11.7%. The nitrogen mostly passed through the combustion chamber unreacted in the simulations, though a small amount of NO_(x) gas was formed.

The HRSG cooled the exhaust in the simulations from 1052° F. to 134° F., but does not otherwise change the composition of the exhaust, which leaves as flue gas 796. Water is not removed in this simulation, but in other arrangements, the HRSG could condense and remove water from the exhaust. Though not simulated in this case, the presence of a duct burner in the HRSG could further increase the concentration of CO₂ and reduce the concentration of oxygen.

Parallel Operation of Two Combustion Turbine Generators

FIG. 9 schematically shows an example of an integrated power generation system 900 including two combustion turbines operated in a parallel arrangement. System 900 includes two combustion turbine generators that produce electricity. The two gas turbines may be the same size and model or be different sizes or models. In practice most installations can use identical CTG trains. Each turbine has a dedicated HRSG for steam generation, but instead of driving two steam turbine generators, the steam is combined and only one steam turbine generator is used. Using a single steam turbine can produce increased reliability, better maintenance scheduling, and economies of scale on the steam turbine. This system can be referred to as a “2×1” configuration. As used herein, system 900 will be described as a 2(p)×1 operation, where the “p” denotes parallel operation. The system 900 is included herein as an alternative base case to illustrate typical characteristics of system exhaust from multiple turbines operating in parallel. These characteristics are explained in more detail with reference to simulation results shown in FIG. 10.

In FIG. 9, the first turbine 901 can include a compressor 902, a shaft 904, an expander 906, and a combustion zone 915. An oxygen source 911 (such as air and/or oxygen-enriched air) can be compressed and heated in compressor 902 prior to entering 913 combustion zone 915. A fuel 912, such as CH₄, can be delivered to the combustion zone 915. The fuel and oxidant can be reacted in zone 915 and optionally but preferably passed 916 through expander 906 to turn shaft 917, which is connected to an electric generator to generate electric power. The exhaust gas 918 can be used as the input for a heat recovery and steam generator system 920, which can, for example, generate steam 994 for steam turbines 995, which generates additional electricity. The exhaust gas 918 leaves the HRSG 920 as a flue gas 997.

The second turbine 930 can include a compressor 932, a shaft 934, an expander 936, and a combustion zone 945. An oxygen source 941 (such as air and/or oxygen-enriched air) can be compressed and heated in compressor 932 prior to entering 943 combustion zone 945. A fuel 942, such as CH₄, can be delivered to the combustion zone 945. The fuel and oxidant can be reacted in zone 945 and optionally but preferably passed 946 through expander 936 to turn shaft 947, which is connected to an electric generator to generate electric power. The exhaust gas 948 can be used as the input for a heat recovery and steam generator system 950, which can, for example, generate steam 993 for steam turbines 995, which generates additional electricity. Optionally, each HRSG 990 and 950 could feed a separate steam turbine instead of the single steam turbine 995 shown. The exhaust gas 948 leaves the HRSG 990 as a flue gas 998.

As an example, simulations were performed using a configuration similar to the system shown in FIG. 9. The results from the simulations are shown in FIG. 10. General Electric's Frame 9Fb.05 turbine was used as the basis for the simulations. The simulation results shown in FIG. 10 show pound moles per hour and concentrations as a mole fraction percent. For the sake of simplicity, the simulations will be described in terms of mole fraction percent.

The air 911 and 941 entered the respective compressors 902 and 932 in the simulations with substantially no CO₂. The air 911 and 941 contained about 20.8% oxygen. The fuel fed into the turbine's combustion chamber in the simulations was about 93% methane. During combustion, the methane was combined with O₂ to create CO₂ and water. The simulations were performed to have complete combustion of methane. The air to methane ratio was about 24.6:1 in the simulations shown.

The turbine exhaust 918 and 948 had a CO₂ concentration of about 4.2% and an O₂ concentration of about 11.7% as it entered the HRSG in the simulations. Thus, the CO₂ concentration increased from approximately 0% to 4.2% and the O₂ concentration decreased from approximately 20.8% to about 11.7%. The nitrogen mostly passed through the combustion chamber unreacted in the simulations, though a small amount of NO_(x) gas is formed.

The HRSG 920 and 950 cooled the exhaust from 1052° F. to 134° F. in the simulations, but did not otherwise change the composition of the exhaust. The HRSG did not remove water from the exhaust in this simulation, but in other arrangements, the HRSG could condense and remove water from the exhaust. Though not simulated in this case, the presence of a duct burner in the HRSG could further increase the concentration of CO₂ and reduce the concentration of oxygen. As each turbine is simulated to have identical performance, the combined turbine exhaust appears to have exactly the same concentrations as the individual exhaust produced by each turbine.

Exhaust Gas Recycle with Combustion Turbine Generator

FIGS. 11 and 12 schematically show examples of integrated power generation systems 1100 including exhaust gas recycle. In FIG. 11, the turbine 1101 can include a compressor 1102, a shaft 1104, an expander 1106, and a combustion zone 1115. An oxygen source 1111 (such as air and/or oxygen-enriched air) can be mixed with dry EGR recycle 1151 to form mixed oxygen source 1152. The mixed oxygen source 1152 can be compressed and heated in compressor 1102 prior to entering 1113 combustion zone 1115. A fuel 1112, such as CH₄, can be delivered to the combustion zone 1115. The fuel and oxidant can be reacted in zone 1115 and optionally but preferably passed 1116 through expander 1106 to turn shaft 1117, which is connected to an electric generator to generate electric power. The exhaust gas 1118 can be used as the input for a heat recovery and steam generator system 1120, which can, for example, generate steam 1194 for steam turbines 1195, which generates additional electricity. Flue gas 1156 may be feed to the atmosphere or into another process (not shown), for example, an Amine scrubber for CO₂ stripping. A portion of the HRSG 1190 exhaust is recycled 1198 to the turbine 1101. In one aspect, 35% of the exhaust gas is recycled. Stream 1150 can be a water knockout from the recycle loop 1198.

FIG. 12 includes many of the same components as described previously in FIG. 11. However, instead of feeding substantially all of the turbine's exhaust gas into the HRSG 1190, the exhaust gas is split prior to the HRSG 1190 and instead introduced into HRSG 1290, which cools the exhaust gas and can remove water prior to recycling 1198 back to the turbine 1101.

As an example, simulations were performed using a configuration similar to the system shown in FIGS. 11 and 12. The results from the simulations are shown in FIG. 13. General Electric's Frame 9Fb.05 turbine was used as the basis for the simulations. The simulation results shown in FIG. 13 show pound moles per hour and concentrations as a mole fraction percent. For the sake of simplicity, the simulations will be described in terms of mole fraction percent.

The air 1111 entered the compressor 1102 in the simulations with substantially no CO₂. The air 1111 contained about 20.8% oxygen. When combined with the EEG recycle in the simulations, the CO₂ concentration increased to about 2.4% and the oxygen decreased to about 16.7%. The water knockout 1150 reduced the water concentration in the raw turbine exhaust in the simulations from about 8.7% to about 0.5%.

The fuel fed into the turbine's combustion chamber in the simulations was about 93% methane. During combustion, the methane was combined with O₂ to create CO₂ and water. The simulation were performed to have complete combustion of methane. The air to methane ratio was about 24.6:1 in the simulations shown.

The turbine exhaust 1192 had a CO₂ concentration of about 6.4% and an O₂ concentration of about 7.8% as it entered the HRSG in the simulations. Thus, the CO₂ concentration increased from approximately 2.4% to 6.4% and the O₂ concentration decreased from approximately 16.7% to approximately 6.4%. The nitrogen mostly passed through the combustion chamber unreacted in the simulations, though a small amount of NO_(x) gas was formed.

The HRSG 1190 cooled the exhaust in the simulations, but did not otherwise change the composition of the exhaust. The HRSG did not remove water from the exhaust in this simulation, but in other arrangements the HRSG could condense and remove water from the exhaust. Though not simulated in this case, the presence of a duct burner in the HRSG could further increase the concentration of CO₂ and reduce the concentration of oxygen.

Comparison of CO₂ Removal

In various aspects, it may be desirable to remove the CO₂ from the flue gas. Separation of CO₂ from the flue gas (or combustion exhaust) from combustion turbines has conventionally been performed using an amine scrubber, which can provide a convenient method for comparison. Instead of using an amine scrubber, using the flue gas as at least a part of the cathode inlet stream for an MCFC can allow for transport of CO₂ from the cathode to the anode, where the CO₂ can be separated more readily due to the much higher CO₂ concentration in the anode exhaust.

The increased CO₂ concentration that results from operating the combustion turbines in series can generally increase the efficiency of processes for separating CO₂. The simulations shown above in FIGS. 5-13 each show how much total gas needs to be processed by, for example, an amine scrubber in each arrangement and how much CO₂ is captured on a mass basis, assuming 90% removal. Table 1 shows the CO₂ capture results of the 2(s)×1 simulation described previously with reference to FIGS. 5 and 6, the 1×1 simulation described previously with reference to FIGS. 7 and 8, the 2(p)×1 simulation described previously with reference to FIGS. 9 and 10, and 35% EGR simulation described previously with reference to FIGS. 11-13. Table 1 shows the total exhaust gas generated along with the exhaust gas's CO₂ concentration. Table 1 also shows the amount of CO₂ removed at a 90% capture rate in an amine scrubber and the CO₂ capture ratio in each simulation.

TABLE 1 Comparison of CO₂ capture results 2(s) × 1 1 × 1 2(p) × 1 35% EGR (FIGS. 5-6) (FIGS. 7-8) (FIGS. 9-10) (FIGS. 11-13) Exhaust ~211,000 ~212,000 ~424,000 ~138,000 (lbmol/hr) CO₂ Conc. ~8.3 mol % ~4.2 mol % ~4.2 mol % ~6.4 mol % CO₂ Capture  ~16,000  ~7,900  ~16,000  ~7,900 (lbmol/hr) Capture ~13.3:1 ~26.7:1 ~26.7:1 ~17.4:1 Ratio

The simulation results of FIG. 6 show that at a 90% capture rate, one amine scrubbing tower would process 211,319 lbmol/hr of total gas flow and capture approximately 15,835 lbmol/hr of CO₂, or a ratio of 13.3:1. This shows that a substantially lower total gas volume can be processed to capture a similar amount of CO₂, as compared with an example where two separately operated combustion turbines are used. This can have a further benefit for an MCFC, as the exhaust CO₂ concentration of 8.3 mol % shown in FIG. 6 means that at least about 80% of the CO₂ in the exhaust can be transferred from a cathode stream to an anode stream in an MCFC while still maintaining a sufficient CO₂ concentration in the cathode for operation of the MCFC in a desirable operating regime.

The simulation results of FIG. 8 show that for a base case single turbine configuration, one amine scrubbing tower with a 90% capture rate would process 211,779 lbmol/hr of total gas flow and capture approximately 7,946 lbmol/hr of CO₂, or a ratio of 26.7:1. As a reminder, the exhaust from the single turbine simulated in FIG. 8 produced a CO₂ concentration of 4.2%.

The simulation results of FIG. 10 show that for a base case parallel turbine configuration, one amine scrubbing tower with a 90% capture rate would process 423,559 lbmol/hr of total gas flow and capture approximately 15,892 lbmol/hr of CO₂, or a ratio of 26.7:1. As a reminder, the exhaust from the parallel turbines simulated in FIG. 10 produced a CO₂ concentration of 4.2%.

The simulation results of FIG. 13, showing a base case where a turbine was run with 35% EGR, show that at a 90% capture rate, one amine scrubbing tower would process 137,667 lbmol/hr of total gas flow and capture approximately 7,925 lbmol/hr of CO₂, or a ratio of 17.4:1.

Accordingly, in an aspect, operating two turbines in series can improve the flue gas processed to CO₂ captured ratio from about 26.7:1 with a single turbine (or about 17.4:1 with 35% EGR) to about 13.3:1. More generally, operating two turbines in series can improve the ratio of flue gas processed to CO₂ captured from a ratio of at least about 15:1, or at least about 17:1, or at least about 20:1, to a ratio of about 14.5:1 or less, or about 14:1 or less, or about 13.5:1 or less. The improved ratio can result in lowered operating cost and lower capital outlay per mole of CO₂ captured.

Fuel Cell Operation Strategies for Processing Multiple Turbine Exhausts in Series

As shown in FIG. 4, the exhaust from a train of combustion turbines operated in series can be introduced into a fuel cell cathode for further processing. What follows is an explanation of various strategies for operating molten carbonate fuel cells to process the CO₂.

As an addition, complement, and/or alternative to the fuel cell operating strategies described herein, a molten carbonate fuel cell can be operated so that the amount of reforming can be selected relative to the amount of oxidation in order to achieve a desired thermal ratio for the fuel cell. As used herein, the “thermal ratio” is defined as the heat produced by exothermic reactions in a fuel cell assembly divided by the endothermic heat demand of reforming reactions occurring within the fuel cell assembly. Expressed mathematically, the thermal ratio (TH)=Q_(EX)/Q_(EN), where Q_(EX) is the sum of heat produced by exothermic reactions and Q_(EN) is the sum of heat consumed by the endothermic reactions occurring within the fuel cell. Note that the heat produced by the exothermic reactions corresponds to any heat due to reforming reactions, water gas shift reactions, and the electrochemical reactions in the cell. The heat generated by the electrochemical reactions can be calculated based on the ideal electrochemical potential of the fuel cell reaction across the electrolyte minus the actual output voltage of the fuel cell. For example, the ideal electrochemical potential of the reaction in a MCFC is believed to be about 1.04V based on the net reaction that occurs in the cell. During operation of the MCFC, the cell will typically have an output voltage less than 1.04 V due to various losses. For example, a common output/operating voltage can be about 0.7 V. The heat generated is equal to the electrochemical potential of the cell (i.e., ˜1.04V) minus the operating voltage. For example, the heat produced by the electrochemical reactions in the cell is ˜0.34 V when the output voltage of ˜0.7V. Thus, in this scenario, the electrochemical reactions would produce ˜0.7 V of electricity and ˜0.34 V of heat energy. In such an example, the ˜0.7 V of electrical energy is not included as part of Q_(EX). In other words, heat energy is not electrical energy.

In various aspects, a thermal ratio can be determined for any convenient fuel cell structure, such as a fuel cell stack, an individual fuel cell within a fuel cell stack, a fuel cell stack with an integrated reforming stage, a fuel cell stack with an integrated endothermic reaction stage, or a combination thereof. The thermal ratio may also be calculated for different units within a fuel cell stack, such as an assembly of fuel cells or fuel cell stacks. For example, the thermal ratio may be calculated for a single anode within a single fuel cell, an anode section within a fuel cell stack, or an anode section within a fuel cell stack along with integrated reforming stages and/or integrated endothermic reaction stage elements in sufficiently close proximity to the anode section to be integrated from a heat integration standpoint. As used herein, “an anode section” comprises anodes within a fuel cell stack that share a common inlet or outlet manifold.

In various aspects of the invention, the operation of the fuel cells can be characterized based on a thermal ratio. Where fuel cells are operated to have a desired thermal ratio, a molten carbonate fuel cell can be operated to have a thermal ratio of about 1.5 or less, for example about 1.3 or less, or about 1.15 or less, or about 1.0 or less, or about 0.95 or less, or about 0.90 or less, or about 0.85 or less, or about 0.80 or less, or about 0.75 or less. Additionally or alternately, the thermal ratio can be at least about 0.25, or at least about 0.35, or at least about 0.45, or at least about 0.50. Additionally or alternately, in some aspects the fuel cell can be operated to have a temperature rise between anode input and anode output of about 40° C. or less, such as about 20° C. or less, or about 10° C. or less. Further additionally or alternately, the fuel cell can be operated to have an anode outlet temperature that is from about 10° C. lower to about 10° C. higher than the temperature of the anode inlet. Still further additionally or alternately, the fuel cell can be operated to have an anode inlet temperature that is greater than the anode outlet temperature, such as at least about 5° C. greater, or at least about 10° C. greater, or at least about 20° C. greater, or at least about 25° C. greater. Yet still further additionally or alternately, the fuel cell can be operated to have an anode inlet temperature that is greater than the anode outlet temperature by about 100° C. or less, such as by about 80° C. or less, or about 60° C. or less, or about 50° C. or less, or about 40° C. or less, or about 30° C. or less, or about 20° C. or less.

As an addition, complement, and/or alternative to the fuel cell operating strategies described herein, a molten carbonate fuel cell (such as a fuel cell assembly) can be operated with increased production of syngas (or hydrogen) while also reducing or minimizing the amount of CO₂ exiting the fuel cell in the cathode exhaust stream. Syngas can be a valuable input for a variety of processes. In addition to having fuel value, syngas can be used as a raw material for forming other higher value products, such as by using syngas as an input for Fischer-Tropsch synthesis and/or methanol synthesis processes. One option for making syngas can be to reform a hydrocarbon or hydrocarbon-like fuel, such as methane or natural gas. For many types of industrial processes, a syngas having a ratio of H₂ to CO of close to 2:1 (or even lower) can often be desirable. A water gas shift reaction can be used to reduce the H₂ to CO ratio in a syngas if additional CO₂ is available, such as is produced in the anodes.

One way of characterizing the overall benefit provided by integrating syngas generation with use of molten carbonate fuel cells can be based on a ratio of the net amount of syngas that exits the fuel cells in the anode exhaust relative to the amount of CO₂ that exits the fuel cells in the cathode exhaust. This characterization measures the effectiveness of producing power with low emissions and high efficiency (both electrical and chemical). In this description, the net amount of syngas in an anode exhaust is defined as the combined number of moles of H₂ and number of moles of CO present in the anode exhaust, offset by the amount of H₂ and CO present in the anode inlet. Because the ratio is based on the net amount of syngas in the anode exhaust, simply passing excess H₂ into the anode does not change the value of the ratio. However, H₂ and/or CO generated due to reforming in the anode and/or in an internal reforming stage associated with the anode can lead to higher values of the ratio. Hydrogen oxidized in the anode can lower the ratio. It is noted that the water gas shift reaction can exchange H₂ for CO, so the combined moles of H₂ and CO represents the total potential syngas in the anode exhaust, regardless of the eventual desired ratio of H₂ to CO in a syngas. The syngas content of the anode exhaust (H₂+CO) can then be compared with the CO₂ content of the cathode exhaust. This can provide a type of efficiency value that can also account for the amount of carbon capture. This can equivalently be expressed as an equation as

Ratio of net syngas in anode exhaust to cathode CO₂=net moles of (H₂+CO)_(ANODE)/moles of (CO₂)_(CATHODE)

In various aspects, the ratio of net moles of syngas in the anode exhaust to the moles of CO₂ in the cathode exhaust can be at least about 2.0, such as at least about 3.0, or at least about 4.0, or at least about 5.0. In some aspects, the ratio of net syngas in the anode exhaust to the amount of CO₂ in the cathode exhaust can be still higher, such as at least about 10.0, or at least about 15.0, or at least about 20.0. Ratio values of about 40.0 or less, such as about 30.0 or less, or about 20.0 or less, can additionally or alternately be achieved. In aspects where the amount of CO₂ at the cathode inlet is about 6.0 vol % or less, such as about 5.0 vol % or less, ratio values of at least about 1.5 may be sufficient/realistic. Such molar ratio values of net syngas in the anode exhaust to the amount of CO₂ in the cathode exhaust can be greater than the values for conventionally operated fuel cells.

As an addition, complement, and/or alternative to the fuel cell operating strategies described herein, a molten carbonate fuel cell (such as a fuel cell assembly) can be operated at a reduced fuel utilization value, such as a fuel utilization of about 50% or less, while also having a high CO₂ utilization value, such as at least about 60%. In this type of configuration, the molten carbonate fuel cell can be effective for carbon capture, as the CO₂ utilization can advantageously be sufficiently high. Rather than attempting to maximize electrical efficiency, in this type of configuration the total efficiency of the fuel cell can be improved or increased based on the combined electrical and chemical efficiency. The chemical efficiency can be based on withdrawal of a hydrogen and/or syngas stream from the anode exhaust as an output for use in other processes. Even though the electrical efficiency may be reduced relative to some conventional configurations, making use of the chemical energy output in the anode exhaust can allow for a desirable total efficiency for the fuel cell.

In various aspects, the fuel utilization in the fuel cell anode can be about 50% or less, such as about 40% or less, or about 30% or less, or about 25% or less, or about 20% or less. In various aspects, in order to generate at least some electric power, the fuel utilization in the fuel cell can be at least about 5%, such as at least about 10%, or at least about 15%, or at least about 20%, or at least about 25%, or at least about 30%. Additionally or alternatively, the CO₂ utilization can be at least about 60%, such as at least about 65%, or at least about 70%, or at least about 75%.

As an addition, complement, and/or alternative to the fuel cell operating strategies described herein, a molten carbonate fuel cell can be operated at conditions that increase or maximize syngas production, possibly at the detriment of electricity production and electrical efficiency. Instead of selecting the operating conditions of a fuel cell to improve or maximize the electrical efficiency of the fuel cell, operating conditions, possibly including an amount of reformable fuel passed into the anode, can be established to increase the chemical energy output of the fuel cell. These operating conditions can result in a lower electrical efficiency of the fuel cell. Despite the reduced electrical efficiency, optionally, but preferably, the operating conditions can lead to an increase in the total efficiency of the fuel cell, which is based on the combined electrical efficiency and chemical efficiency of the fuel cell. By increasing the ratio of reformable fuel introduced into the anode to the fuel that is actually electrochemically oxidized at the anode, the chemical energy content in the anode output can be increased.

In some aspects, the reformable hydrogen content of reformable fuel in the input stream delivered to the anode and/or to a reforming stage associated with the anode can be at least about 50% greater than the net amount of hydrogen reacted at the anode, such as at least about 75% greater or at least about 100% greater. Additionally or alternately, the reformable hydrogen content of fuel in the input stream delivered to the anode and/or to a reforming stage associated with the anode can be at least about 50% greater than the net amount of hydrogen reacted at the anode, such as at least about 75% greater or at least about 100% greater. In various aspects, a ratio of the reformable hydrogen content of the reformable fuel in the fuel stream relative to an amount of hydrogen reacted in the anode can be at least about 1.5:1, or at least about 2.0:1, or at least about 2.5:1, or at least about 3.0:1. Additionally or alternately, the ratio of reformable hydrogen content of the reformable fuel in the fuel stream relative to the amount of hydrogen reacted in the anode can be about 20:1 or less, such as about 15:1 or less or about 10:1 or less. In one aspect, it is contemplated that less than 100% of the reformable hydrogen content in the anode inlet stream can be converted to hydrogen. For example, at least about 80% of the reformable hydrogen content in an anode inlet stream can be converted to hydrogen in the anode and/or in an associated reforming stage(s), such as at least about 85%, or at least about 90%. Additionally or alternately, the amount of reformable fuel delivered to the anode can be characterized based on the Lower Heating Value (LHV) of the reformable fuel relative to the LHV of the hydrogen oxidized in the anode. This can be referred to as a reformable fuel surplus ratio. In various aspects, the reformable fuel surplus ratio can be at least about 2.0, such as at least about 2.5, or at least about 3.0, or at least about 4.0. Additionally or alternately, the reformable fuel surplus ratio can be about 25.0 or less, such as about 20.0 or less, or about 15.0 or less, or about 10.0 or less.

As an addition, complement, and/or alternative to the fuel cell operating strategies described herein, a molten carbonate fuel cell (such as a fuel cell assembly) can also be operated at conditions that can improve or optimize the combined electrical efficiency and chemical efficiency of the fuel cell. Instead of selecting conventional conditions for maximizing the electrical efficiency of a fuel cell, the operating conditions can allow for output of excess synthesis gas and/or hydrogen in the anode exhaust of the fuel cell. The synthesis gas and/or hydrogen can then be used in a variety of applications, including chemical synthesis processes and collection of hydrogen for use as a “clean” fuel. In aspects of the invention, electrical efficiency can be reduced to achieve a high overall efficiency, which includes a chemical efficiency based on the chemical energy value of syngas and/or hydrogen produced relative to the energy value of the fuel input for the fuel cell.

In some aspects, the operation of the fuel cells can be characterized based on electrical efficiency. Where fuel cells are operated to have a low electrical efficiency (EE), a molten carbonate fuel cell can be operated to have an electrical efficiency of about 40% or less, for example, about 35% EE or less, about 30% EE or less, about 25% EE or less, or about 20% EE or less, about 15% EE or less, or about 10% EE or less. Additionally or alternately, the EE can be at least about 5%, or at least about 10%, or at least about 15%, or at least about 20%. Further additionally or alternately, the operation of the fuel cells can be characterized based on total fuel cell efficiency (TFCE), such as a combined electrical efficiency and chemical efficiency of the fuel cell(s). Where fuel cells are operated to have a high total fuel cell efficiency, a molten carbonate fuel cell can be operated to have a TFCE (and/or combined electrical efficiency and chemical efficiency) of about 55% or more, for example, about 60% or more, or about 65% or more, or about 70% or more, or about 75% or more, or about 80% or more, or about 85% or more. It is noted that for a total fuel cell efficiency and/or combined electrical efficiency and chemical efficiency, any additional electricity generated from use of excess heat generated by the fuel cell can be excluded from the efficiency calculation.

In various aspects of the invention, the operation of the fuel cells can be characterized based on a desired electrical efficiency of about 40% or less and a desired total fuel cell efficiency of about 55% or more. Where fuel cells are operated to have a desired electrical efficiency and a desired total fuel cell efficiency, a molten carbonate fuel cell can be operated to have an electrical efficiency of about 40% or less with a TFCE of about 55% or more, for example, about 35% EE or less with about a TFCE of 60% or more, about 30% EE or less with about a TFCE of about 65% or more, about 25% EE or less with about a 70% TFCE or more, or about 20% EE or less with about a TFCE of 75% or more, about 15% EE or less with about a TFCE of 80% or more, or about 10% EE or less with about a TFCE of about 85% or more.

As an addition, complement, and/or alternative to the fuel cell operating strategies described herein, a molten carbonate fuel cell (such as a fuel cell assembly) can be operated at conditions that can provide increased power density. The power density of a fuel cell corresponds to the actual operating voltage V_(A) multiplied by the current density I. For a molten carbonate fuel cell operating at a voltage V_(A), the fuel cell also can tend to generate waste heat, the waste heat defined as (V₀−V_(A))*I based on the differential between V_(A) and the ideal voltage V₀ for a fuel cell providing current density I. A portion of this waste heat can be consumed by reforming of a reformable fuel within the anode of the fuel cell. The remaining portion of this waste heat can be absorbed by the surrounding fuel cell structures and gas flows, resulting in a temperature differential across the fuel cell. Under conventional operating conditions, the power density of a fuel cell can be limited based on the amount of waste heat that the fuel cell can tolerate without compromising the integrity of the fuel cell.

In various aspects, the amount of waste heat that a fuel cell can tolerate can be increased by performing an effective amount of an endothermic reaction within the fuel cell. One example of an endothermic reaction includes steam reforming of a reformable fuel within a fuel cell anode and/or in an associated reforming stage, such as an integrated reforming stage in a fuel cell stack. By providing additional reformable fuel to the anode of the fuel cell (or to an integrated/associated reforming stage), additional reforming can be performed so that additional waste heat can be consumed. This can reduce the amount of temperature differential across the fuel cell, thus allowing the fuel cell to operate under an operating condition with an increased amount of waste heat. The loss of electrical efficiency can be offset by the creation of an additional product stream, such as syngas and/or H₂, that can be used for various purposes including additional electricity generation further expanding the power range of the system.

In various aspects, the amount of waste heat generated by a fuel cell, (V₀−V_(A))*I as defined above, can be at least about 30 mW/cm², such as at least about 40 mW/cm², or at least about 50 mW/cm², or at least about 60 mW/cm², or at least about 70 mW/cm², or at least about 80 mW/cm², or at least about 100 mW/cm², or at least about 120 mW/cm², or at least about 140 mW/cm², or at least about 160 mW/cm², or at least about 180 mW/cm². Additionally or alternately, the amount of waste heat generated by a fuel cell can be less than about 250 mW/cm², such as less than about 200 mW/cm², or less than about 180 mW/cm², or less than about 165 mW/cm², or less than about 150 mW/cm².

Although the amount of waste heat being generated can be relatively high, such waste heat may not necessarily represent operating a fuel cell with poor efficiency. Instead, the waste heat can be generated due to operating a fuel cell at an increased power density. Part of improving the power density of a fuel cell can include operating the fuel cell at a sufficiently high current density. In various aspects, the current density generated by the fuel cell can be at least about 150 mA/cm², such as at least about 160 mA/cm², or at least about 170 mA/cm², or at least about 180 mA/cm², or at least about 190 mA/cm², or at least about 200 mA/cm², or at least about 225 mA/cm², or at least about 250 mA/cm². Additionally or alternately, the current density generated by the fuel cell can be about 500 mA/cm² or less, such as 450 mA/cm², or less, or 400 mA/cm², or less or 350 mA/cm², or less or 300 mA/cm² or less.

In various aspects, to allow a fuel cell to be operated with increased power generation and increased generation of waste heat, an effective amount of an endothermic reaction (such as a reforming reaction) can be performed. Alternatively, other endothermic reactions unrelated to anode operations can be used to utilize the waste heat by interspersing “plates” or stages into the fuel cell array that are in thermal communication but not fluid communication. The effective amount of the endothermic reaction can be performed in an associated reforming stage, an integrated reforming stage, an integrated stack element for performing an endothermic reaction, or a combination thereof. The effective amount of the endothermic reaction can correspond to an amount sufficient to reduce the temperature rise from the fuel cell inlet to the fuel cell outlet to about 100° C. or less, such as about 90° C. or less, or about 80° C. or less, or about 70° C. or less, or about 60° C. or less, or about 50° C. or less, or about 40° C. or less, or about 30° C. or less. Additionally or alternately, the effective amount of the endothermic reaction can correspond to an amount sufficient to cause a temperature decrease from the fuel cell inlet to the fuel cell outlet of about 100° C. or less, such as about 90° C. or less, or about 80° C. or less, or about 70° C. or less, or about 60° C. or less, or about 50° C. or less, or about 40° C. or less, or about 30° C. or less, or about 20° C. or less, or about 10° C. or less. A temperature decrease from the fuel cell inlet to the fuel cell outlet can occur when the effective amount of the endothermic reaction exceeds the waste heat generated. Additionally or alternately, this can correspond to having the endothermic reaction(s) (such as a combination of reforming and another endothermic reaction) consume at least about 40% of the waste heat generated by the fuel cell, such as consuming at least about 50% of the waste heat, or at least about 60% of the waste heat, or at least about 75% of the waste heat. Further additionally or alternately, the endothermic reaction(s) can consume about 95% of the waste heat or less, such as about 90% of the waste heat or less, or about 85% of the waste heat or less.

As an addition, complement, and/or alternative to the fuel cell operating strategies described herein, a molten carbonate fuel cell (such as a fuel cell assembly) can be operated at conditions corresponding to a decreased operating voltage and a low fuel utilization. In various aspects, the fuel cell can be operated at a voltage V_(A) of less than about 0.7 Volts, for example less than about 0.68 V, less than about 0.67 V, less than about 0.66 V, or about 0.65 V or less. Additionally or alternatively, the fuel cell can be operated at a voltage V_(A) of at least about 0.60, for example at least about 0.61, at least about 0.62, or at least about 0.63. In so doing, energy that would otherwise leave the fuel cell as electrical energy at high voltage can remain within the cell as heat as the voltage is lowered. This additional heat can allow for increased endothermic reactions to occur, for example increasing the CH₄ conversion to syngas.

DEFINITIONS

Combustion Turbine:

In this description, a combustion turbine is defined as a turbine where the product of combustion (e.g., a hot pressurized vapor stream) is used directly to turn a turbine. This definition excludes a steam turbine where the product of combustion is used to heat a separate fluid, such as water to produce steam, that is used directly to turn a turbine.

Syngas:

In this description, syngas is defined as mixture of H₂ and CO in any ratio. Optionally, H₂O and/or CO₂ may be present in the syngas. Optionally, inert compounds (such as nitrogen) and residual reformable fuel compounds may be present in the syngas. If components other than H₂ and CO are present in the syngas, the combined volume percentage of H₂ and CO in the syngas can be at least 25 vol % relative to the total volume of the syngas, such as at least 40 vol %, or at least 50 vol %, or at least 60 vol %. Additionally or alternately, the combined volume percentage of H₂ and CO in the syngas can be 100 vol % or less, such as 95 vol % or less or 90 vol % or less.

Reformable Fuel:

A reformable fuel is defined as a fuel that contains carbon-hydrogen bonds that can be reformed to generate H₂. Hydrocarbons are examples of reformable fuels, as are other hydrocarbonaceous compounds such as alcohols. Although CO and H₂O can participate in a water gas shift reaction to form hydrogen, CO is not considered a reformable fuel under this definition.

Reformable Hydrogen Content:

The reformable hydrogen content of a fuel is defined as the number of H₂ molecules that can be derived from a fuel by reforming the fuel and then driving the water gas shift reaction to completion to maximize H₂ production. It is noted that H₂ by definition has a reformable hydrogen content of 1, although H₂ itself is not defined as a reformable fuel herein. Similarly, CO has a reformable hydrogen content of 1. Although CO is not strictly reformable, driving the water gas shift reaction to completion will result in exchange of a CO for an H₂. As examples of reformable hydrogen content for reformable fuels, the reformable hydrogen content of methane is 4 H₂ molecules while the reformable hydrogen content of ethane is 7 H₂ molecules. More generally, if a fuel has the composition CxHyOz, then the reformable hydrogen content of the fuel at 100% reforming and water-gas shift is n(H₂ max reforming)=2x+y/2−z. Based on this definition, fuel utilization within a cell can then be expressed as n(H₂ ox)/n(H₂ max reforming) Of course, the reformable hydrogen content of a mixture of components can be determined based on the reformable hydrogen content of the individual components. The reformable hydrogen content of compounds that contain other heteroatoms, such as oxygen, sulfur or nitrogen, can also be calculated in a similar manner.

Oxidation Reaction:

In this discussion, the oxidation reaction within the anode of a fuel cell is defined as the reaction corresponding to oxidation of H₂ by reaction with CO₃ ²⁻ to form H₂O and CO₂. It is noted that the reforming reaction within the anode, where a compound containing a carbon-hydrogen bond is converted into H₂ and CO or CO₂, is excluded from this definition of the oxidation reaction in the anode. The water-gas shift reaction is similarly outside of this definition of the oxidation reaction. It is further noted that references to a combustion reaction are defined as references to reactions where H₂ or a compound containing carbon-hydrogen bond(s) are reacted with O₂ to form H₂O and carbon oxides in a non-electrochemical burner, such as the combustion zone of a combustion-powered generator.

Aspects of the invention can adjust anode fuel parameters to achieve a desired operating range for the fuel cell. Anode fuel parameters can be characterized directly, and/or in relation to other fuel cell processes in the form of one or more ratios. For example, the anode fuel parameters can be controlled to achieve one or more ratios including a fuel utilization, a fuel cell heating value utilization, a fuel surplus ratio, a reformable fuel surplus ratio, a reformable hydrogen content fuel ratio, and combinations thereof.

Fuel Utilization:

Fuel utilization is an option for characterizing operation of the anode based on the amount of oxidized fuel relative to the reformable hydrogen content of an input stream can be used to define a fuel utilization for a fuel cell. In this discussion, “fuel utilization” is defined as the ratio of the amount of hydrogen oxidized in the anode for production of electricity (as described above) versus the reformable hydrogen content of the anode input (including any associated reforming stages). Reformable hydrogen content has been defined above as the number of H₂ molecules that can be derived from a fuel by reforming the fuel and then driving the water gas shift reaction to completion to maximize H₂ production. For example, each methane introduced into an anode and exposed to steam reforming conditions results in generation of the equivalent of 4 H₂ molecules at max production. (Depending on the reforming and/or anode conditions, the reforming product can correspond to a non-water gas shifted product, where one or more of the H₂ molecules is present instead in the form of a CO molecule.) Thus, methane is defined as having a reformable hydrogen content of 4 H₂ molecules. As another example, under this definition ethane has a reformable hydrogen content of 7 H₂ molecules.

The utilization of fuel in the anode can also be characterized by defining a heating value utilization based on a ratio of the Lower Heating Value of hydrogen oxidized in the anode due to the fuel cell anode reaction relative to the Lower Heating Value of all fuel delivered to the anode and/or a reforming stage associated with the anode. The “fuel cell heating value utilization” as used herein can be computed using the flow rates and Lower Heating Value (LHV) of the fuel components entering and leaving the fuel cell anode. As such, fuel cell heating value utilization can be computed as (LHV(anode_in)−LHV(anode_out))/LHV(anode_in), where LHV(anode_in) and LHV(anode_out) refer to the LHV of the fuel components (such as H₂, CH₄, and/or CO) in the anode inlet and outlet streams or flows, respectively. In this definition, the LHV of a stream or flow may be computed as a sum of values for each fuel component in the input and/or output stream. The contribution of each fuel component to the sum can correspond to the fuel component's flow rate (e.g., mol/hr) multiplied by the fuel component's LHV (e.g., joules/mol).

Lower Heating Value:

The lower heating value is defined as the enthalpy of combustion of a fuel component to vapor phase, fully oxidized products (e.g., vapor phase CO₂ and H₂O product). For example, any CO₂ present in an anode input stream does not contribute to the fuel content of the anode input, since CO₂ is already fully oxidized. For this definition, the amount of oxidation occurring in the anode due to the anode fuel cell reaction is defined as oxidation of H₂ in the anode as part of the electrochemical reaction in the anode, as defined above.

It is noted that, for the special case where the only fuel in the anode input flow is H₂, the only reaction involving a fuel component that can take place in the anode represents the conversion of H₂ into H₂O. In this special case, the fuel utilization simplifies to (H₂-rate-in minus H₂-rate-out)/H₂-rate-in. In such a case, H₂ would be the only fuel component, and so the H₂ LHV would cancel out of the equation. In the more general case, the anode feed may contain, for example, CH₄, H₂, and CO in various amounts. Because these species can typically be present in different amounts in the anode outlet, the summation as described above can be needed to determine the fuel utilization.

Alternatively or in addition to fuel utilization, the utilization for other reactants in the fuel cell can be characterized. For example, the operation of a fuel cell can additionally or alternately be characterized with regard to “CO₂ utilization” and/or “oxidant” utilization. The values for CO₂ utilization and/or oxidant utilization can be specified in a similar manner.

Fuel Surplus Ratio:

Still another way to characterize the reactions in a molten carbonate fuel cell is by defining a utilization based on a ratio of the Lower Heating Value of all fuel delivered to the anode and/or a reforming stage associated with the anode relative to the Lower Heating Value of hydrogen oxidized in the anode due to the fuel cell anode reaction. This quantity will be referred to as a fuel surplus ratio. As such the fuel surplus ratio can be computed as (LHV (anode_in)/(LHV(anode_in)−LHV(anode_out)) where LHV(anode_in) and LHV(anode_out) refer to the LHV of the fuel components (such as H₂, CH₄, and/or CO) in the anode inlet and outlet streams or flows, respectively. In various aspects of the invention, a molten carbonate fuel cell can be operated to have a fuel surplus ratio of at least about 1.0, such as at least about 1.5, or at least about 2.0, or at least about 2.5, or at least about 3.0, or at least about 4.0. Additionally or alternately, the fuel surplus ratio can be about 25.0 or less.

It is noted that not all of the reformable fuel in the input stream for the anode may be reformed. Preferably, at least about 90% of the reformable fuel in the input stream to the anode (and/or into an associated reforming stage) can be reformed prior to exiting the anode, such as at least about 95% or at least about 98%. In some alternative aspects, the amount of reformable fuel that is reformed can be from about 75% to about 90%, such as at least about 80%.

The above definition for fuel surplus ratio provides a method for characterizing the amount of reforming occurring within the anode and/or reforming stage(s) associated with a fuel cell relative to the amount of fuel consumed in the fuel cell anode for generation of electric power.

Optionally, the fuel surplus ratio can be modified to account for situations where fuel is recycled from the anode output to the anode input. When fuel (such as H₂, CO, and/or unreformed or partially reformed hydrocarbons) is recycled from anode output to anode input, such recycled fuel components do not represent a surplus amount of reformable or reformed fuel that can be used for other purposes. Instead, such recycled fuel components merely indicate a desire to reduce fuel utilization in a fuel cell.

Reformable Fuel Surplus Ratio:

Calculating a reformable fuel surplus ratio is one option to account for such recycled fuel components is to narrow the definition of surplus fuel, so that only the LHV of reformable fuels is included in the input stream to the anode. As used herein the “reformable fuel surplus ratio” is defined as the Lower Heating Value of reformable fuel delivered to the anode and/or a reforming stage associated with the anode relative to the Lower Heating Value of hydrogen oxidized in the anode due to the fuel cell anode reaction. Under the definition for reformable fuel surplus ratio, the LHV of any H₂ or CO in the anode input is excluded. Such an LHV of reformable fuel can still be measured by characterizing the actual composition entering a fuel cell anode, so no distinction between recycled components and fresh components needs to be made. Although some non-reformed or partially reformed fuel may also be recycled, in most aspects the majority of the fuel recycled to the anode can correspond to reformed products such as H₂ or CO. Expressed mathematically, the reformable fuel surplus ratio (R_(RFS))=LHV_(RF)/LHV_(OH), where LHV_(RF) is the Lower Heating Value (LHV) of the reformable fuel and LHV_(OH) is the Lower Heating Value (LHV) of the hydrogen oxidized in the anode. The LHV of the hydrogen oxidized in the anode may be calculated by subtracting the LHV of the anode outlet stream from the LHV of the anode inlet stream (e.g., LHV(anode_in)−LHV(anode_out)). In various aspects of the invention, a molten carbonate fuel cell can be operated to have a reformable fuel surplus ratio of at least about 0.25, such as at least about 0.5, or at least about 1.0, or at least about 1.5, or at least about 2.0, or at least about 2.5, or at least about 3.0, or at least about 4.0. Additionally or alternately, the reformable fuel surplus ratio can be about 25.0 or less. It is noted that this narrower definition based on the amount of reformable fuel delivered to the anode relative to the amount of oxidation in the anode can distinguish between two types of fuel cell operation methods that have low fuel utilization. Some fuel cells achieve low fuel utilization by recycling a substantial portion of the anode output back to the anode input. This recycle can allow any hydrogen in the anode input to be used again as an input to the anode. This can reduce the amount of reforming, as even though the fuel utilization is low for a single pass through the fuel cell, at least a portion of the unused fuel is recycled for use in a later pass. Thus, fuel cells with a wide variety of fuel utilization values may have the same ratio of reformable fuel delivered to the anode reforming stage(s) versus hydrogen oxidized in the anode reaction. In order to change the ratio of reformable fuel delivered to the anode reforming stages relative to the amount of oxidation in the anode, either an anode feed with a native content of non-reformable fuel needs to be identified, or unused fuel in the anode output needs to be withdrawn for other uses, or both.

Reformable Hydrogen Surplus Ratio:

Still another option for characterizing the operation of a fuel cell is based on a “reformable hydrogen surplus ratio.” The reformable fuel surplus ratio defined above is defined based on the lower heating value of reformable fuel components. The reformable hydrogen surplus ratio is defined as the reformable hydrogen content of reformable fuel delivered to the anode and/or a reforming stage associated with the anode relative to the hydrogen reacted in the anode due to the fuel cell anode reaction. As such, the “reformable hydrogen surplus ratio” can be computed as (RFC(reformable_anode_in)/(RFC(reformable_anode_in)−RFC(anode_out)), where RFC(reformable_anode_in) refers to the reformable hydrogen content of reformable fuels in the anode inlet streams or flows, while RFC (anode_out) refers to the reformable hydrogen content of the fuel components (such as H₂, CH₄, and/or CO) in the anode inlet and outlet streams or flows. The RFC can be expressed in moles/s, moles/hr, or similar. An example of a method for operating a fuel cell with a large ratio of reformable fuel delivered to the anode reforming stage(s) versus amount of oxidation in the anode can be a method where excess reforming is performed in order to balance the generation and consumption of heat in the fuel cell. Reforming a reformable fuel to form H₂ and CO is an endothermic process. This endothermic reaction can be countered by the generation of electrical current in the fuel cell, which can also produce excess heat corresponding (roughly) to the difference between the amount of heat generated by the anode oxidation reaction and the carbonate formation reaction and the energy that exits the fuel cell in the form of electric current. The excess heat per mole of hydrogen involved in the anode oxidation reaction/carbonate formation reaction can be greater than the heat absorbed to generate a mole of hydrogen by reforming. As a result, a fuel cell operated under conventional conditions can exhibit a temperature increase from inlet to outlet. Instead of this type of conventional operation, the amount of fuel reformed in the reforming stages associated with the anode can be increased. For example, additional fuel can be reformed so that the heat generated by the exothermic fuel cell reactions can be (roughly) balanced by the heat consumed in reforming, or even the heat consumed by reforming can be beyond the excess heat generated by the fuel oxidation, resulting in a temperature drop across the fuel cell. This can result in a substantial excess of hydrogen relative to the amount needed for electrical power generation. As one example, a feed to the anode inlet of a fuel cell or an associated reforming stage can be substantially composed of reformable fuel, such as a substantially pure methane feed. During conventional operation for electric power generation using such a fuel, a molten carbonate fuel cell can be operated with a fuel utilization of about 75%. This means that about 75% (or ¾) of the fuel content delivered to the anode is used to form hydrogen that is then reacted in the anode with carbonate ions to form H₂O and CO₂. In conventional operation, the remaining about 25% of the fuel content can be reformed to H₂ within the fuel cell (or can pass through the fuel cell unreacted for any CO or H₂ in the fuel), and then combusted outside of the fuel cell to form H₂O and CO₂ to provide heat for the cathode inlet to the fuel cell. The reformable hydrogen surplus ratio in this situation can be 4/(4−1)=4/3.

Electrical Efficiency:

As used herein, the term “electrical efficiency” (“EE”) is defined as the electrochemical power produced by the fuel cell divided by the rate of Lower Heating Value (“LHV”) of fuel input to the fuel cell. The fuel inputs to the fuel cell includes both fuel delivered to the anode as well as any fuel used to maintain the temperature of the fuel cell, such as fuel delivered to a burner associated with a fuel cell. In this description, the power produced by the fuel may be described in terms of LHV(el) fuel rate.

Electrochemical Power:

As used herein, the term “electrochemical power” or LHV(el) is the power generated by the circuit connecting the cathode to the anode in the fuel cell and the transfer of carbonate ions across the fuel cell's electrolyte. Electrochemical power excludes power produced or consumed by equipment upstream or downstream from the fuel cell. For example, electricity produced from heat in a fuel cell exhaust stream is not considered part of the electrochemical power. Similarly, power generated by a gas turbine or other equipment upstream of the fuel cell is not part of the electrochemical power generated. The “electrochemical power” does not take electrical power consumed during operation of the fuel cell into account, or any loss incurred by conversion of the direct current to alternating current. In other words, electrical power used to supply the fuel cell operation or otherwise operate the fuel cell is not subtracted from the direct current power produced by the fuel cell. As used herein, the power density is the current density multiplied by voltage. As used herein, the total fuel cell power is the power density multiplied by the fuel cell area.

Fuel Inputs:

As used herein, the term “anode fuel input,” designated as LHV(anode_in), is the amount of fuel within the anode inlet stream. The term “fuel input”, designated as LHV(in), is the total amount of fuel delivered to the fuel cell, including both the amount of fuel within the anode inlet stream and the amount of fuel used to maintain the temperature of the fuel cell. The fuel may include both reformable and nonreformable fuels, based on the definition of a reformable fuel provided herein. Fuel input is not the same as fuel utilization.

Total Fuel Cell Efficiency:

As used herein, the term “total fuel cell efficiency” (“TFCE”) is defined as: the electrochemical power generated by the fuel cell, plus the rate of LHV of syngas produced by the fuel cell, divided by the rate of LHV of fuel input to the anode. In other words, TFCE=(LHV(el)+LHV(sg net))/LHV(anode_in), where LHV(anode_in) refers to rate at which the LHV of the fuel components (such as H₂, CH₄, and/or CO) delivered to the anode and LHV(sg net) refers to a rate at which syngas (H₂, CO) is produced in the anode, which is the difference between syngas input to the anode and syngas output from the anode. LHV(el) describes the electrochemical power generation of the fuel cell. The total fuel cell efficiency excludes heat generated by the fuel cell that is put to beneficial use outside of the fuel cell. In operation, heat generated by the fuel cell may be put to beneficial use by downstream equipment. For example, the heat may be used to generate additional electricity or to heat water. These uses, when they occur apart from the fuel cell, are not part of the total fuel cell efficiency, as the term is used in this application. The total fuel cell efficiency is for the fuel cell operation only, and does not include power production, or consumption, upstream, or downstream, of the fuel cell.

Chemical Efficiency:

As used herein, the term “chemical efficiency”, is defined as the lower heating value of H₂ and CO in the anode exhaust of the fuel cell, or LHV(sg out), divided by the fuel input, or LHV(in).

Neither the electrical efficiency nor the total system efficiency takes the efficiency of upstream or downstream processes into consideration. For example, it may be advantageous to use turbine exhaust as a source of CO₂ for the fuel cell cathode. In this arrangement, the efficiency of the turbine is not considered as part of the electrical efficiency or the total fuel cell efficiency calculation. Similarly, outputs from the fuel cell may be recycled as inputs to the fuel cell. A recycle loop is not considered when calculating electrical efficiency or the total fuel cell efficiency in single pass mode.

Syngas Produced:

As used herein, the term “syngas produced” is the difference between syngas input to the anode and syngas output from the anode. Syngas may be used as an input, or fuel, for the anode, at least in part. For example, a system may include an anode recycle loop that returns syngas from the anode exhaust to the anode inlet where it is supplemented with natural gas or other suitable fuel. Syngas produced LHV (sg net)=(LHV(sg out)−LHV(sg in)), where LHV(sg in) and LHV(sg out) refer to the LHV of the syngas in the anode inlet and syngas in the anode outlet streams or flows, respectively. It is noted that at least a portion of the syngas produced by the reforming reactions within an anode can typically be utilized in the anode to produce electricity. The hydrogen utilized to produce electricity is not included in the definition of “syngas produced” because it does not exit the anode. As used herein, the term “syngas ratio” is the LHV of the net syngas produced divided by the LHV of the fuel input to the anode or LHV (sg net)/LHV(anode in). Molar flow rates of syngas and fuel can be used instead of LHV to express a molar-based syngas ratio and a molar-based syngas produced.

Steam to Carbon Ratio (S/C):

As used herein, the steam to carbon ratio (S/C) is the molar ratio of steam in a flow to reformable carbon in the flow. Carbon in the form of CO and CO₂ are not included as reformable carbon in this definition. The steam to carbon ratio can be measured and/or controlled at different points in the system. For example, the composition of an anode inlet stream can be manipulated to achieve a S/C that is suitable for reforming in the anode. The S/C can be given as the molar flow rate of H₂O divided by the product of the molar flow rate of fuel multiplied by the number of carbon atoms in the fuel, e.g., one for methane. Thus, S/C=f_(H20)/(f_(CH4)×#C), where f_(H20) is the molar flow rate of water, where f_(CH4) is the molar flow rate of methane (or other fuel) and #C is the number of carbons in the fuel.

EGR Ratio:

Aspects of the invention can use a turbine in partnership with a fuel cell. The combined fuel cell and turbine system may include exhaust gas recycle (“EGR”). In an EGR system, at least a portion of the exhaust gas generated by the turbine can be sent to a heat recovery generator. Another portion of the exhaust gas can be sent to the fuel cell. The EGR ratio describes the amount of exhaust gas routed to the fuel cell versus the total exhaust gas routed to either the fuel cell or heat recovery generator. As used herein, the “EGR ratio” is the flow rate for the fuel cell bound portion of the exhaust gas divided by the combined flow rate for the fuel cell bound portion and the recovery bound portion, which is sent to the heat recovery generator.

In various aspects of the invention, a molten carbonate fuel cell (MCFC) can be used to facilitate separation of CO₂ from a CO₂-containing stream while also generating additional electrical power. The CO₂ separation can be further enhanced by taking advantage of synergies with the combustion-based power generator that can provide at least a portion of the input feed to the cathode portion of the fuel cell.

Fuel Cell and Fuel Cell Components:

In this discussion, a fuel cell can correspond to a single cell, with an anode and a cathode separated by an electrolyte. The anode and cathode can receive input gas flows to facilitate the respective anode and cathode reactions for transporting charge across the electrolyte and generating electricity. A fuel cell stack can represent a plurality of cells in an integrated unit. Although a fuel cell stack can include multiple fuel cells, the fuel cells can typically be connected in parallel and can function (approximately) as if they collectively represented a single fuel cell of a larger size. When an input flow is delivered to the anode or cathode of a fuel cell stack, the fuel stack can include flow channels for dividing the input flow between each of the cells in the stack and flow channels for combining the output flows from the individual cells. In this discussion, a fuel cell array can be used to refer to a plurality of fuel cells (such as a plurality of fuel cell stacks) that are arranged in series, in parallel, or in any other convenient manner (e.g., in a combination of series and parallel). A fuel cell array can include one or more stages of fuel cells and/or fuel cell stacks, where the anode/cathode output from a first stage may serve as the anode/cathode input for a second stage. It is noted that the anodes in a fuel cell array do not have to be connected in the same way as the cathodes in the array. For convenience, the input to the first anode stage of a fuel cell array may be referred to as the anode input for the array, and the input to the first cathode stage of the fuel cell array may be referred to as the cathode input to the array. Similarly, the output from the final anode/cathode stage may be referred to as the anode/cathode output from the array.

It should be understood that reference to use of a fuel cell herein typically denotes a “fuel cell stack” composed of individual fuel cells, and more generally refers to use of one or more fuel cell stacks in fluid communication. Individual fuel cell elements (plates) can typically be “stacked” together in a rectangular array called a “fuel cell stack”. This fuel cell stack can typically take a feed stream and distribute reactants among all of the individual fuel cell elements and can then collect the products from each of these elements. When viewed as a unit, the fuel cell stack in operation can be taken as a whole even though composed of many (often tens or hundreds) of individual fuel cell elements. These individual fuel cell elements can typically have similar voltages (as the reactant and product concentrations are similar), and the total power output can result from the summation of all of the electrical currents in all of the cell elements, when the elements are electrically connected in series. Stacks can also be arranged in a series arrangement to produce high voltages. A parallel arrangement can boost the current. If a sufficiently large volume fuel cell stack is available to process a given exhaust flow, the systems and methods described herein can be used with a single molten carbonate fuel cell stack. In other aspects of the invention, a plurality of fuel cell stacks may be desirable or needed for a variety of reasons.

For the purposes of this invention, unless otherwise specified, the term “fuel cell” should be understood to also refer to and/or is defined as including a reference to a fuel cell stack composed of set of one or more individual fuel cell elements for which there is a single input and output, as that is the manner in which fuel cells are typically employed in practice. Similarly, the term fuel cells (plural), unless otherwise specified, should be understood to also refer to and/or is defined as including a plurality of separate fuel cell stacks. In other words, all references within this document, unless specifically noted, can refer interchangeably to the operation of a fuel cell stack as a “fuel cell”. For example, the volume of exhaust generated by a commercial scale combustion generator may be too large for processing by a fuel cell (e.g., a single stack) of conventional size. In order to process the full exhaust, a plurality of fuel cells (i.e., two or more separate fuel cells or fuel cell stacks) can be arranged in parallel, so that each fuel cell can process (roughly) an equal portion of the combustion exhaust. Although multiple fuel cells can be used, each fuel cell can typically be operated in a generally similar manner, given its (roughly) equal portion of the combustion exhaust.

“Internal Reforming” and “External Reforming”:

A fuel cell or fuel cell stack may include one or more internal reforming sections. As used herein, the term “internal reforming” refers to fuel reforming occurring within the body of a fuel cell, a fuel cell stack, or otherwise within a fuel cell assembly. External reforming, which is often used in conjunction with a fuel cell, occurs in a separate piece of equipment that is located outside of the fuel cell stack. In other words, the body of the external reformer is not in direct physical contact with the body of a fuel cell or fuel cell stack. In a typical set up, the output from the external reformer can be fed to the anode inlet of a fuel cell. Unless otherwise noted specifically, the reforming described within this application is internal reforming.

Internal reforming may occur within a fuel cell anode. Internal reforming can additionally or alternately occur within an internal reforming element integrated within a fuel cell assembly. The integrated reforming element may be located between fuel cell elements within a fuel cell stack. In other words, one of the trays in the stack can be a reforming section instead of a fuel cell element. In one aspect, the flow arrangement within a fuel cell stack directs fuel to the internal reforming elements and then into the anode portion of the fuel cells. Thus, from a flow perspective, the internal reforming elements and fuel cell elements can be arranged in series within the fuel cell stack. As used herein, the term “anode reforming” is fuel reforming that occurs within an anode. As used herein, the term “internal reforming” is reforming that occurs within an integrated reforming element and not in an anode section.

In some aspects, a reforming stage that is internal to a fuel cell assembly can be considered to be associated with the anode(s) in the fuel cell assembly. In some alternative aspects, for a reforming stage in a fuel cell stack that can be associated with an anode (such as associated with multiple anodes), a flow path can be available so that the output flow from the reforming stage is passed into at least one anode. This can correspond to having an initial section of a fuel cell plate not in contact with the electrolyte and instead can serve just as a reforming catalyst. Another option for an associated reforming stage can be to have a separate integrated reforming stage as one of the elements in a fuel cell stack, where the output from the integrated reforming stage can be returned to the input side of one or more of the fuel cells in the fuel cell stack.

From a heat integration standpoint, a characteristic height in a fuel cell stack can be the height of an individual fuel cell stack element. It is noted that the separate reforming stage and/or a separate endothermic reaction stage could have a different height in the stack than a fuel cell. In such a scenario, the height of a fuel cell element can be used as the characteristic height. In some aspects, an integrated endothermic reaction stage can be defined as a stage that is heat integrated with one or more fuel cells, so that the integrated endothermic reaction stage can use the heat from the fuel cells as a heat source for the endothermic reaction. Such an integrated endothermic reaction stage can be defined as being positioned less than 5 times the height of a stack element from any fuel cells providing heat to the integrated stage. For example, an integrated endothermic reaction stage (such as a reforming stage) can be positioned less than 5 times the height of a stack element from any fuel cells that are heat integrated, such as less than 3 times the height of a stack element. In this discussion, an integrated reforming stage and/or integrated endothermic reaction stage that represent an adjacent stack element to a fuel cell element can be defined as being about one stack element height or less away from the adjacent fuel cell element.

In some aspects, a separate reforming stage that is heat integrated with a fuel cell element can correspond to a reforming stage associated with the fuel cell element. In such aspects, an integrated fuel cell element can provide at least a portion of the heat to the associated reforming stage, and the associated reforming stage can provide at least a portion of the reforming stage output to the integrated fuel cell as a fuel stream. In other aspects, a separate reforming stage can be integrated with a fuel cell for heat transfer without being associated with the fuel cell. In this type of situation, the separate reforming stage can receive heat from the fuel cell, but the decision can be made not to use the output of the reforming stage as an input to the fuel cell. Instead, the decision can be made to use the output of such a reforming stage for another purpose, such as directly adding the output to the anode exhaust stream, and/or for forming a separate output stream from the fuel cell assembly.

More generally, a separate stack element in a fuel cell stack can be used to perform any convenient type of endothermic reaction that can take advantage of the waste heat provided by integrated fuel cell stack elements. Instead of plates suitable for performing a reforming reaction on a hydrocarbon fuel stream, a separate stack element can have plates suitable for catalyzing another type of endothermic reaction. A manifold or other arrangement of inlet conduits in the fuel cell stack can be used to provide an appropriate input flow to each stack element. A similar manifold or other arrangement of outlet conduits can additionally or alternately be used to withdraw the output flows from each stack element. Optionally, the output flows from a endothermic reaction stage in a stack can be withdrawn from the fuel cell stack without having the output flow pass through a fuel cell anode. In such an optional aspect, the products of the exothermic reaction can therefore exit from the fuel cell stack without passing through a fuel cell anode. Examples of other types of endothermic reactions that can be performed in stack elements in a fuel cell stack can include, without limitation, ethanol dehydration to form ethylene and ethane cracking.

Recycle:

As defined herein, recycle of a portion of a fuel cell output (such as an anode exhaust or a stream separated or withdrawn from an anode exhaust) to a fuel cell inlet can correspond to a direct or indirect recycle stream. A direct recycle of a stream to a fuel cell inlet is defined as recycle of the stream without passing through an intermediate process, while an indirect recycle involves recycle after passing a stream through one or more intermediate processes. For example, if the anode exhaust is passed through a CO₂ separation stage prior to recycle, this is considered an indirect recycle of the anode exhaust. If a portion of the anode exhaust, such as an H₂ stream withdrawn from the anode exhaust, is passed into a gasifier for converting coal into a fuel suitable for introduction into the fuel cell, then that is also considered an indirect recycle.

Anode Inputs and Outputs

In various aspects of the invention, the MCFC array can be fed by a fuel received at the anode inlet that comprises, for example, both hydrogen and a hydrocarbon such as methane (or alternatively a hydrocarbonaceous or hydrocarbon-like compound that may contain heteroatoms different from C and H). Most of the methane (or other hydrocarbonaceous or hydrocarbon-like compound) fed to the anode can typically be fresh methane. In this description, a fresh fuel such as fresh methane refers to a fuel that is not recycled from another fuel cell process. For example, methane recycled from the anode outlet stream back to the anode inlet may not be considered “fresh” methane, and can instead be described as reclaimed methane. The fuel source used can be shared with other components, such as a turbine that uses a portion of the fuel source to provide a CO₂-containing stream for the cathode input. The fuel source input can include water in a proportion to the fuel appropriate for reforming the hydrocarbon (or hydrocarbon-like) compound in the reforming section that generates hydrogen. For example, if methane is the fuel input for reforming to generate H₂, the molar ratio of water to fuel can be from about one to one to about ten to one, such as at least about two to one. A ratio of four to one or greater is typical for external reforming, but lower values can be typical for internal reforming To the degree that H₂ is a portion of the fuel source, in some optional aspects no additional water may be needed in the fuel, as the oxidation of H₂ at the anode can tend to produce H₂O that can be used for reforming the fuel. The fuel source can also optionally contain components incidental to the fuel source (e.g., a natural gas feed can contain some content of CO₂ as an additional component). For example, a natural gas feed can contain CO₂, N₂, and/or other inert (noble) gases as additional components. Optionally, in some aspects the fuel source may also contain CO, such as CO from a recycled portion of the anode exhaust. An additional or alternate potential source for CO in the fuel into a fuel cell assembly can be CO generated by steam reforming of a hydrocarbon fuel performed on the fuel prior to entering the fuel cell assembly.

More generally, a variety of types of fuel streams may be suitable for use as an input stream for the anode of a molten carbonate fuel cell. Some fuel streams can correspond to streams containing hydrocarbons and/or hydrocarbon-like compounds that may also include heteroatoms different from C and H. In this discussion, unless otherwise specified, a reference to a fuel stream containing hydrocarbons for an MCFC anode is defined to include fuel streams containing such hydrocarbon-like compounds. Examples of hydrocarbon (including hydrocarbon-like) fuel streams include natural gas, streams containing C1-C4 carbon compounds (such as methane or ethane), and streams containing heavier C5+ hydrocarbons (including hydrocarbon-like compounds), as well as combinations thereof. Still other additional or alternate examples of potential fuel streams for use in an anode input can include biogas-type streams, such as methane produced from natural (biological) decomposition of organic material.

In some aspects, a molten carbonate fuel cell can be used to process an input fuel stream, such as a natural gas and/or hydrocarbon stream, with a low energy content due to the presence of diluent compounds. For example, some sources of methane and/or natural gas are sources that can include substantial amounts of either CO₂ or other inert molecules, such as nitrogen, argon, or helium. Due to the presence of elevated amounts of CO₂ and/or inerts, the energy content of a fuel stream based on the source can be reduced. Using a low energy content fuel for a combustion reaction (such as for powering a combustion-powered turbine) can pose difficulties. However, a molten carbonate fuel cell can generate power based on a low energy content fuel source with a reduced or minimal impact on the efficiency of the fuel cell. The presence of additional gas volume can require additional heat for raising the temperature of the fuel to the temperature for reforming and/or the anode reaction. Additionally, due to the equilibrium nature of the water gas shift reaction within a fuel cell anode, the presence of additional CO₂ can have an impact on the relative amounts of H₂ and CO present in the anode output. However, the inert compounds otherwise can have only a minimal direct impact on the reforming and anode reactions. The amount of CO₂ and/or inert compounds in a fuel stream for a molten carbonate fuel cell, when present, can be at least about 1 vol %, such as at least about 2 vol %, or at least about 5 vol %, or at least about 10 vol %, or at least about 15 vol %, or at least about 20 vol %, or at least about 25 vol %, or at least about 30 vol %, or at least about 35 vol %, or at least about 40 vol %, or at least about 45 vol %, or at least about 50 vol %, or at least about 75 vol %. Additionally or alternately, the amount of CO₂ and/or inert compounds in a fuel stream for a molten carbonate fuel cell can be about 90 vol % or less, such as about 75 vol % or less, or about 60 vol % or less, or about 50 vol % or less, or about 40 vol % or less, or about 35 vol % or less.

Yet other examples of potential sources for an anode input stream can correspond to refinery and/or other industrial process output streams. For example, coking is a common process in many refineries for converting heavier compounds to lower boiling ranges. Coking typically produces an off-gas containing a variety of compounds that are gases at room temperature, including CO and various C1-C4 hydrocarbons. This off-gas can be used as at least a portion of an anode input stream. Other refinery off-gas streams can additionally or alternately be suitable for inclusion in an anode input stream, such as light ends (C1-C4) generated during cracking or other refinery processes. Still other suitable refinery streams can additionally or alternately include refinery streams containing CO or CO₂ that also contain H₂ and/or reformable fuel compounds.

Still other potential sources for an anode input can additionally or alternately include streams with increased water content. For example, an ethanol output stream from an ethanol plant (or another type of fermentation process) can include a substantial portion of H₂O prior to final distillation. Such H₂O can typically cause only minimal impact on the operation of a fuel cell. Thus, a fermentation mixture of alcohol (or other fermentation product) and water can be used as at least a portion of an anode input stream.

Biogas, or digester gas, is another additional or alternate potential source for an anode input. Biogas may primarily comprise methane and CO₂ and is typically produced by the breakdown or digestion of organic matter. Anaerobic bacteria may be used to digest the organic matter and produce the biogas. Impurities, such as sulfur-containing compounds, may be removed from the biogas prior to use as an anode input.

The output stream from an MCFC anode can include H₂O, CO₂, CO, and H₂. Optionally, the anode output stream could also have unreacted fuel (such as H₂ or CH₄) or inert compounds in the feed as additional output components. Instead of using this output stream as a fuel source to provide heat for a reforming reaction or as a combustion fuel for heating the cell, one or more separations can be performed on the anode output stream to separate the CO₂ from the components with potential value as inputs to another process, such as H₂ or CO. The H₂ and/or CO can be used as a syngas for chemical synthesis, as a source of hydrogen for chemical reaction, and/or as a fuel with reduced greenhouse gas emissions.

In various aspects, the composition of the output stream from the anode can be impacted by several factors. Factors that can influence the anode output composition can include the composition of the input stream to the anode, the amount of current generated by the fuel cell, and/or the temperature at the exit of the anode. The temperature of at the anode exit can be relevant due to the equilibrium nature of the water gas shift reaction. In a typical anode, at least one of the plates forming the wall of the anode can be suitable for catalyzing the water gas shift reaction. As a result, if a) the composition of the anode input stream is known, b) the extent of reforming of reformable fuel in the anode input stream is known, and c) the amount of carbonate transported from the cathode to anode (corresponding to the amount of electrical current generated) is known, the composition of the anode output can be determined based on the equilibrium constant for the water gas shift reaction.

K _(eq)=[CO₂][H₂]/[CO][H₂O]

In the above equation, K_(eq) is the equilibrium constant for the reaction at a given temperature and pressure, and [X] is the partial pressure of component X. Based on the water gas shift reaction, it can be noted that an increased CO₂ concentration in the anode input can tend to result in additional CO formation (at the expense of H₂) while an increased H₂O concentration can tend to result in additional H₂ formation (at the expense of CO).

To determine the composition at the anode output, the composition of the anode input can be used as a starting point. This composition can then be modified to reflect the extent of reforming of any reformable fuels that can occur within the anode. Such reforming can reduce the hydrocarbon content of the anode input in exchange for increased hydrogen and CO₂. Next, based on the amount of electrical current generated, the amount of H₂ in the anode input can be reduced in exchange for additional H₂O and CO₂. This composition can then be adjusted based on the equilibrium constant for the water gas shift reaction to determine the exit concentrations for H₂, CO, CO₂, and H₂O.

Table 1 shows the anode exhaust composition at different fuel utilizations for a typical type of fuel. The anode exhaust composition can reflect the combined result of the anode reforming reaction, water gas shift reaction, and the anode oxidation reaction. The output composition values in Table 1 were calculated by assuming an anode input composition with an about 2 to 1 ratio of steam (H₂O) to carbon (reformable fuel). The reformable fuel was assumed to be methane, which was assumed to be 100% reformed to hydrogen. The initial CO₂ and H₂ concentrations in the anode input were assumed to be negligible, while the input N₂ concentration was about 0.5%. The fuel utilization U_(f) (as defined herein) was allowed to vary from about 35% to about 70% as shown in the table. The exit temperature for the fuel cell anode was assumed to be about 650° C. for purposes of determining the correct value for the equilibrium constant.

TABLE 2 Anode Exhaust Composition Uf % ~35% ~40% ~45% ~50% ~55% ~60% ~65% ~70% Anode Exhaust Composition H₂O %, wet 32.5% 34.1% 35.5% 36.7% 37.8% 38.9% 39.8% 40.5% CO₂ %, wet 26.7% 29.4% 32.0% 34.5% 36.9% 39.3% 41.5% 43.8% H₂ %, wet 29.4% 26.0% 22.9% 20.0% 17.3% 14.8% 12.5% 10.4% CO %, wet 10.8% 10.0% 9.2% 8.4% 7.5% 6.7% 5.8% 4.9% N₂ %, wet 0.5% 0.5% 0.5% 0.4% 0.4% 0.4% 0.4% 0.4% CO₂ %, dry 39.6% 44.6% 49.6% 54.5% 59.4% 64.2% 69.0% 73.7% H₂ %, dry 43.6% 39.4% 35.4% 31.5% 27.8% 24.2% 20.7% 17.5% CO %, dry 16.1% 15.2% 14.3% 13.2% 12.1% 10.9% 9.7% 8.2% N₂ %, dry 0.7% 0.7% 0.7% 0.7% 0.7% 0.7% 0.7% 0.7% H₂/CO 2.7 2.6 2.5 2.4 2.3 2.2 2.1 2.1 (H₂ − CO₂)/ 0.07 −0.09 −0.22 −0.34 −0.44 −0.53 −0.61 −0.69 (CO + CO₂)

Table 2 shows anode output compositions for a particular set of conditions and anode input composition. More generally, in various aspects the anode output can include about 10 vol % to about 50 vol % H₂O. The amount of H₂O can vary greatly, as H₂O in the anode can be produced by the anode oxidation reaction. If an excess of H₂O beyond what is needed for reforming is introduced into the anode, the excess H₂O can typically pass through largely unreacted, with the exception of H₂O consumed (or generated) due to fuel reforming and the water gas shift reaction. The CO₂ concentration in the anode output can also vary widely, such as from about 20 vol % to about 50 vol % CO₂. The amount of CO₂ can be influenced by both the amount of electrical current generated as well as the amount of CO₂ in the anode input flow. The amount of H₂ in the anode output can additionally or alternately be from about 10 vol % H₂ to about 50 vol % H₂, depending on the fuel utilization in the anode. At the anode output, the amount of CO can be from about 5 vol % to about 20 vol %. It is noted that the amount of CO relative to the amount of H₂ in the anode output for a given fuel cell can be determined in part by the equilibrium constant for the water gas shift reaction at the temperature and pressure present in the fuel cell. The anode output can further additionally or alternately include 5 vol % or less of various other components, such as N₂, CH₄ (or other unreacted carbon-containing fuels), and/or other components.

Optionally, one or more water gas shift reaction stages can be included after the anode output to convert CO and H₂O in the anode output into CO₂ and H₂, if desired. The amount of H₂ present in the anode output can be increased, for example, by using a water gas shift reactor at lower temperature to convert H₂O and CO present in the anode output into H₂ and CO₂. Alternatively, the temperature can be raised and the water-gas shift reaction can be reversed, producing more CO and H₂O from H₂ and CO₂. Water is an expected output of the reaction occurring at the anode, so the anode output can typically have an excess of H₂O relative to the amount of CO present in the anode output. Alternatively, H₂O can be added to the stream after the anode exit but before the water gas shift reaction. CO can be present in the anode output due to incomplete carbon conversion during reforming and/or due to the equilibrium balancing reactions between H₂O, CO, H₂, and CO₂ (i.e., the water-gas shift equilibrium) under either reforming conditions or the conditions present during the anode reaction. A water gas shift reactor can be operated under conditions to drive the equilibrium further in the direction of forming CO₂ and H₂ at the expense of CO and H₂O. Higher temperatures can tend to favor the formation of CO and H₂O. Thus, one option for operating the water gas shift reactor can be to expose the anode output stream to a suitable catalyst, such as a catalyst including iron oxide, zinc oxide, copper on zinc oxide, or the like, at a suitable temperature, e.g., between about 190° C. to about 210° C. Optionally, the water-gas shift reactor can include two stages for reducing the CO concentration in an anode output stream, with a first higher temperature stage operated at a temperature from at least about 300° C. to about 375° C. and a second lower temperature stage operated at a temperature of about 225° C. or less, such as from about 180° C. to about 210° C. In addition to increasing the amount of H₂ present in the anode output, the water-gas shift reaction can additionally or alternately increase the amount of CO₂ at the expense of CO. This can exchange difficult-to-remove carbon monoxide (CO) for carbon dioxide, which can be more readily removed by condensation (e.g., cryogenic removal), chemical reaction (such as amine removal), and/or other CO₂ removal methods. Additionally or alternately, it may be desirable to increase the CO content present in the anode exhaust in order to achieve a desired ratio of H₂ to CO.

After passing through the optional water gas shift reaction stage, the anode output can be passed through one or more separation stages for removal of water and/or CO₂ from the anode output stream. For example, one or more CO₂ output streams can be formed by performing CO₂ separation on the anode output using one or more methods individually or in combination. Such methods can be used to generate CO₂ output stream(s) having a CO₂ content of 90 vol % or greater, such as at least 95% vol % CO₂, or at least 98 vol % CO₂. Such methods can recover about at least about 70% of the CO₂ content of the anode output, such as at least about 80% of the CO₂ content of the anode output, or at least about 90%. Alternatively, in some aspects it may be desirable to recover only a portion of the CO₂ within an anode output stream, with the recovered portion of CO₂ being about 33% to about 90% of the CO₂ in the anode output, such as at least about 40%, or at least about 50%. For example, it may be desirable to retain some CO₂ in the anode output flow so that a desired composition can be achieved in a subsequent water gas shift stage. Suitable separation methods may comprise use of a physical solvent (e.g., Selexol™ or Rectisol™); amines or other bases (e.g., MEA or MDEA); refrigeration (e.g., cryogenic separation); pressure swing adsorption; vacuum swing adsorption; and combinations thereof. A cryogenic CO₂ separator can be an example of a suitable separator. As the anode output is cooled, the majority of the water in the anode output can be separated out as a condensed (liquid) phase. Further cooling and/or pressurizing of the water-depleted anode output flow can then separate high purity CO₂, as the other remaining components in the anode output flow (such as H₂, N₂, CH₄) do not tend to readily form condensed phases. A cryogenic CO₂ separator can recover between about 33% and about 90% of the CO₂ present in a flow, depending on the operating conditions.

Removal of water from the anode exhaust to form one or more water output streams can also be beneficial, whether prior to, during, or after performing CO₂ separation. The amount of water in the anode output can vary depending on operating conditions selected. For example, the steam-to-carbon ratio established at the anode inlet can affect the water content in the anode exhaust, with high steam-to-carbon ratios typically resulting in a large amount of water that can pass through the anode unreacted and/or reacted only due to the water gas shift equilibrium in the anode. Depending on the aspect, the water content in the anode exhaust can correspond to up to about 30% or more of the volume in the anode exhaust. Additionally or alternately, the water content can be about 80% or less of the volume of the anode exhaust. While such water can be removed by compression and/or cooling with resulting condensation, the removal of this water can require extra compressor power and/or heat exchange surface area and excessive cooling water. One beneficial way to remove a portion of this excess water can be based on use of an adsorbent bed that can capture the humidity from the moist anode effluent and can then be ‘regenerated’ using dry anode feed gas, in order to provide additional water for the anode feed. HVAC-style (heating, ventilation, and air conditioning) adsorption wheels design can be applicable, because anode exhaust and inlet can be similar in pressure, and minor leakage from one stream to the other can have minimal impact on the overall process. In embodiments where CO₂ removal is performed using a cryogenic process, removal of water prior to or during CO₂ removal may be desirable, including removal by triethyleneglycol (TEG) system and/or desiccants. By contrast, if an amine wash is used for CO₂ removal, water can be removed from the anode exhaust downstream from the CO₂ removal stage.

Alternately or in addition to a CO₂ output stream and/or a water output stream, the anode output can be used to form one or more product streams containing a desired chemical or fuel product. Such a product stream or streams can correspond to a syngas stream, a hydrogen stream, or both syngas product and hydrogen product streams. For example, a hydrogen product stream containing at least about 70 vol % H₂, such as at least about 90 vol % H₂ or at least about 95 vol % H₂, can be formed. Additionally or alternately, a syngas stream containing at least about 70 vol % of H₂ and CO combined, such as at least about 90 vol % of H₂ and CO can be formed. The one or more product streams can have a gas volume corresponding to at least about 75% of the combined H₂ and CO gas volumes in the anode output, such as at least about 85% or at least about 90% of the combined H₂ and CO gas volumes. It is noted that the relative amounts of H₂ and CO in the products streams may differ from the H₂ to CO ratio in the anode output based on use of water gas shift reaction stages to convert between the products.

In some aspects, it can be desirable to remove or separate a portion of the H₂ present in the anode output. For example, in some aspects the H₂ to CO ratio in the anode exhaust can be at least about 3.0:1. By contrast, processes that make use of syngas, such as Fischer-Tropsch synthesis, may consume H₂ and CO in a different ratio, such as a ratio that is closer to 2:1. One alternative can be to use a water gas shift reaction to modify the content of the anode output to have an H₂ to CO ratio closer to a desired syngas composition. Another alternative can be to use a membrane separation to remove a portion of the H₂ present in the anode output to achieve a desired ratio of H₂ and CO, or still alternately to use a combination of membrane separation and water gas shift reactions. One advantage of using a membrane separation to remove only a portion of the H₂ in the anode output can be that the desired separation can be performed under relatively mild conditions. Since one goal can be to produce a retentate that still has a substantial H₂ content, a permeate of high purity hydrogen can be generated by membrane separation without requiring severe conditions. For example, rather than having a pressure on the permeate side of the membrane of about 100 kPaa or less (such as ambient pressure), the permeate side can be at an elevated pressure relative to ambient while still having sufficient driving force to perform the membrane separation. Additionally or alternately, a sweep gas such as methane can be used to provide a driving force for the membrane separation. This can reduce the purity of the H₂ permeate stream, but may be advantageous, depending on the desired use for the permeate stream.

In various aspects of the invention, at least a portion of the anode exhaust stream (preferably after separation of CO₂ and/or H₂O) can be used as a feed for a process external to the fuel cell and associated reforming stages. In various aspects, the anode exhaust can have a ratio of H₂ to CO of about 1.5:1 to about 10:1, such as at least about 3.0:1, or at least about 4.0:1, or at least about 5.0:1. A syngas stream can be generated or withdrawn from the anode exhaust. The anode exhaust gas, optionally after separation of CO₂ and/or H₂O, and optionally after performing a water gas shift reaction and/or a membrane separation to remove excess hydrogen, can correspond to a stream containing substantial portions of H₂ and/or CO. For a stream with a relatively low content of CO, such as a stream where the ratio of H₂ to CO is at least about 3:1, the anode exhaust can be suitable for use as an H₂ feed. Examples of processes that could benefit from an H₂ feed can include, but are not limited to, refinery processes, an ammonia synthesis plant, or a turbine in a (different) power generation system, or combinations thereof. Depending on the application, still lower CO₂ contents can be desirable. For a stream with an H₂-to-CO ratio of less than about 2.2 to 1 and greater than about 1.9 to 1, the stream can be suitable for use as a syngas feed. Examples of processes that could benefit from a syngas feed can include, but are not limited to, a gas-to-liquids plant (such as a plant using a Fischer-Tropsch process with a non-shifting catalyst) and/or a methanol synthesis plant. The amount of the anode exhaust used as a feed for an external process can be any convenient amount. Optionally, when a portion of the anode exhaust is used as a feed for an external process, a second portion of the anode exhaust can be recycled to the anode input and/or recycled to the combustion zone for a combustion-powered generator.

The input streams useful for different types of Fischer-Tropsch synthesis processes can provide an example of the different types of product streams that may be desirable to generate from the anode output. For a Fischer-Tropsch synthesis reaction system that uses a shifting catalyst, such as an iron-based catalyst, the desired input stream to the reaction system can include CO₂ in addition to H₂ and CO. If a sufficient amount of CO₂ is not present in the input stream, a Fischer-Tropsch catalyst with water gas shift activity can consume CO in order to generate additional CO₂, resulting in a syngas that can be deficient in CO. For integration of such a Fischer-Tropsch process with an MCFC fuel cell, the separation stages for the anode output can be operated to retain a desired amount of CO₂ (and optionally H₂O) in the syngas product. By contrast, for a Fischer-Tropsch catalyst based on a non-shifting catalyst, any CO₂ present in a product stream could serve as an inert component in the Fischer-Tropsch reaction system.

In an aspect where the membrane is swept with a sweep gas such as a methane sweep gas, the methane sweep gas can correspond to a methane stream used as the anode fuel or in a different low pressure process, such as a boiler, furnace, gas turbine, or other fuel-consuming device. In such an aspect, low levels of CO₂ permeation across the membrane can have minimal consequence. Such CO₂ that may permeate across the membrane can have a minimal impact on the reactions within the anode, and such CO₂ can remain contained in the anode product. Therefore, the CO₂ (if any) lost across the membrane due to permeation does not need to be transferred again across the MCFC electrolyte. This can significantly reduce the separation selectivity requirement for the hydrogen permeation membrane. This can allow, for example, use of a higher-permeability membrane having a lower selectivity, which can enable use of a lower pressure and/or reduced membrane surface area. In such an aspect of the invention, the volume of the sweep gas can be a large multiple of the volume of hydrogen in the anode exhaust, which can allow the effective hydrogen concentration on the permeate side to be maintained close to zero. The hydrogen thus separated can be incorporated into the turbine-fed methane where it can enhance the turbine combustion characteristics, as described above.

It is noted that excess H₂ produced in the anode can represent a fuel where the greenhouse gases have already been separated. Any CO₂ in the anode output can be readily separated from the anode output, such as by using an amine wash, a cryogenic CO₂ separator, and/or a pressure or vacuum swing absorption process. Several of the components of the anode output (H₂, CO, CH₄) are not easily removed, while CO₂ and H₂O can usually be readily removed. Depending on the embodiment, at least about 90 vol % of the CO₂ in the anode output can be separated out to form a relatively high purity CO₂ output stream. Thus, any CO₂ generated in the anode can be efficiently separated out to form a high purity CO₂ output stream. After separation, the remaining portion of the anode output can correspond primarily to components with chemical and/or fuel value, as well as reduced amounts of CO₂ and/or H₂O. Since a substantial portion of the CO₂ generated by the original fuel (prior to reforming) can have been separated out, the amount of CO₂ generated by subsequent burning of the remaining portion of the anode output can be reduced. In particular, to the degree that the fuel in the remaining portion of the anode output is H₂, no additional greenhouse gases can typically be formed by burning of this fuel.

The anode exhaust can be subjected to a variety of gas processing options, including water-gas shift and separation of the components from each other. Two general anode processing schemes are shown in FIGS. 1 and 2.

FIG. 1 schematically shows an example of a reaction system for operating a fuel cell array of molten carbonate fuel cells in conjunction with a chemical synthesis process. In FIG. 1, a fuel stream 105 is provided to a reforming stage (or stages) 110 associated with the anode 127 of a fuel cell 120, such as a fuel cell that is part of a fuel cell stack in a fuel cell array. The reforming stage 110 associated with fuel cell 120 can be internal to a fuel cell assembly. In some optional aspects, an external reforming stage (not shown) can also be used to reform a portion of the reformable fuel in an input stream prior to passing the input stream into a fuel cell assembly. Fuel stream 105 can preferably include a reformable fuel, such as methane, other hydrocarbons, and/or other hydrocarbon-like compounds such as organic compounds containing carbon-hydrogen bonds. Fuel stream 105 can also optionally contain H₂ and/or CO, such as H₂ and/or CO provided by optional anode recycle stream 185. It is noted that anode recycle stream 185 is optional, and that in many aspects no recycle stream is provided from the anode exhaust 125 back to anode 127, either directly or indirectly via combination with fuel stream 105 or reformed fuel stream 115. After reforming, the reformed fuel stream 115 can be passed into anode 127 of fuel cell 120. A CO₂ and O₂-containing stream 119 can also be passed into cathode 129. A flow of carbonate ions 122, CO₃ ²⁻, from the cathode portion 129 of the fuel cell can provide the remaining reactant needed for the anode fuel cell reactions. Based on the reactions in the anode 127, the resulting anode exhaust 125 can include H₂O, CO₂, one or more components corresponding to incompletely reacted fuel (H₂, CO, CH₄, or other components corresponding to a reformable fuel), and optionally one or more additional nonreactive components, such as N₂ and/or other contaminants that are part of fuel stream 105. The anode exhaust 125 can then be passed into one or more separation stages. For example, a CO₂ removal stage 140 can correspond to a cryogenic CO₂ removal system, an amine wash stage for removal of acid gases such as CO₂, or another suitable type of CO₂ separation stage for separating a CO₂ output stream 143 from the anode exhaust. Optionally, the anode exhaust can first be passed through a water gas shift reactor 130 to convert any CO present in the anode exhaust (along with some H₂O) into CO₂ and H₂ in an optionally water gas shifted anode exhaust 135. Depending on the nature of the CO₂ removal stage, a water condensation or removal stage 150 may be desirable to remove a water output stream 153 from the anode exhaust. Though shown in FIG. 1 after the CO₂ separation stage 140, it may optionally be located before the CO₂ separation stage 140 instead. Additionally, an optional membrane separation stage 160 for separation of H₂ can be used to generate a high purity permeate stream 163 of H₂. The resulting retentate stream 166 can then be used as an input to a chemical synthesis process. Stream 166 could additionally or alternately be shifted in a second water-gas shift reactor 131 to adjust the H₂, CO, and CO₂ content to a different ratio, producing an output stream 168 for further use in a chemical synthesis process. In FIG. 1, anode recycle stream 185 is shown as being withdrawn from the retentate stream 166, but the anode recycle stream 185 could additionally or alternately be withdrawn from other convenient locations in or between the various separation stages. The separation stages and shift reactor(s) could additionally or alternately be configured in different orders, and/or in a parallel configuration. Finally, a stream with a reduced content of CO₂ 139 can be generated as an output from cathode 129. For the sake of simplicity, various stages of compression and heat addition/removal that might be useful in the process, as well as steam addition or removal, are not shown.

As noted above, the various types of separations performed on the anode exhaust can be performed in any convenient order. FIG. 2 shows an example of an alternative order for performing separations on an anode exhaust. In FIG. 2, anode exhaust 125 can be initially passed into separation stage 260 for removing a portion 263 of the hydrogen content from the anode exhaust 125. This can allow, for example, reduction of the H₂ content of the anode exhaust to provide a retentate 266 with a ratio of H₂ to CO closer to 2:1. The ratio of H₂ to CO can then be further adjusted to achieve a desired value in a water gas shift stage 230. The water gas shifted output 235 can then pass through CO₂ separation stage 240 and water removal stage 250 to produce an output stream 275 suitable for use as an input to a desired chemical synthesis process. Optionally, output stream 275 could be exposed to an additional water gas shift stage (not shown). A portion of output stream 275 can optionally be recycled (not shown) to the anode input. Of course, still other combinations and sequencing of separation stages can be used to generate a stream based on the anode output that has a desired composition. For the sake of simplicity, various stages of compression and heat addition/removal that might be useful in the process, as well as steam addition or removal, are not shown.

Cathode Inputs and Outputs

Conventionally, a molten carbonate fuel cell can be operated based on drawing a desired load while consuming some portion of the fuel in the fuel stream delivered to the anode. The voltage of the fuel cell can then be determined by the load, fuel input to the anode, air and CO₂ provided to the cathode, and the internal resistances of the fuel cell. The CO₂ to the cathode can be conventionally provided in part by using the anode exhaust as at least a part of the cathode input stream. By contrast, the present invention can use separate/different sources for the anode input and cathode input. By removing any direct link between the composition of the anode input flow and the cathode input flow, additional options become available for operating the fuel cell, such as to generate excess synthesis gas, to improve capture of carbon dioxide, and/or to improve the total efficiency (electrical plus chemical power) of the fuel cell, among others.

In a molten carbonate fuel cell, the transport of carbonate ions across the electrolyte in the fuel cell can provide a method for transporting CO₂ from a first flow path to a second flow path, where the transport method can allow transport from a lower concentration (the cathode) to a higher concentration (the anode), which can thus facilitate capture of CO₂. Part of the selectivity of the fuel cell for CO₂ separation can be based on the electrochemical reactions allowing the cell to generate electrical power. For nonreactive species (such as N₂) that effectively do not participate in the electrochemical reactions within the fuel cell, there can be an insignificant amount of reaction and transport from cathode to anode. By contrast, the potential (voltage) difference between the cathode and anode can provide a strong driving force for transport of carbonate ions across the fuel cell. As a result, the transport of carbonate ions in the molten carbonate fuel cell can allow CO₂ to be transported from the cathode (lower CO₂ concentration) to the anode (higher CO₂ concentration) with relatively high selectivity. However, a challenge in using molten carbonate fuel cells for carbon dioxide removal can be that the fuel cells have limited ability to remove carbon dioxide from relatively dilute cathode feeds. The voltage and/or power generated by a carbonate fuel cell can start to drop rapidly as the CO₂ concentration falls below about 1 mol %. As the CO₂ concentration drops further, e.g., to below about 0.3 mol %, at some point the voltage across the fuel cell can become low enough that little or no further transport of carbonate may occur and the fuel cell ceases to function. Thus, at least some CO₂ is likely to be present in the exhaust gas from the cathode stage of a fuel cell under commercially viable operating conditions.

The amount of carbon dioxide delivered to the fuel cell cathode(s) can be determined based on the CO₂ content of a source for the cathode inlet. One example of a suitable CO₂-containing stream for use as a cathode input flow can be an output or exhaust flow from a combustion source. Examples of combustion sources include, but are not limited to, sources based on combustion of natural gas, combustion of coal, and/or combustion of other hydrocarbon-type fuels (including biologically derived fuels). Additional or alternate sources can include other types of boilers, fired heaters, furnaces, and/or other types of devices that burn carbon-containing fuels in order to heat another substance (such as water or air). To a first approximation, the CO₂ content of the output flow from a combustion source can be a minor portion of the flow. Even for a higher CO₂ content exhaust flow, such as the output from a coal-fired combustion source, the CO₂ content from most commercial coal-fired power plants can be about 15 vol % or less. More generally, the CO₂ content of an output or exhaust flow from a combustion source can be at least about 1.5 vol %, or at least about 1.6 vol %, or at least about 1.7 vol %, or at least about 1.8 vol %, or at least about 1.9 vol %, or at least greater 2 vol %, or at least about 4 vol %, or at least about 5 vol %, or at least about 6 vol %, or at least about 8 vol %. Additionally or alternately, the CO₂ content of an output or exhaust flow from a combustion source can be about 20 vol % or less, such as about 15 vol % or less, or about 12 vol % or less, or about 10 vol % or less, or about 9 vol % or less, or about 8 vol % or less, or about 7 vol % or less, or about 6.5 vol % or less, or about 6 vol % or less, or about 5.5 vol % or less, or about 5 vol % or less, or about 4.5 vol % or less. The concentrations given above are on a dry basis. It is noted that the lower CO₂ content values can be present in the exhaust from some natural gas or methane combustion sources, such as generators that are part of a power generation system that may or may not include an exhaust gas recycle loop.

Other potential sources for a cathode input stream can additionally or alternately include sources of bio-produced CO₂. This can include, for example, CO₂ generated during processing of bio-derived compounds, such as CO₂ generated during ethanol production. An additional or alternate example can include CO₂ generated by combustion of a bio-produced fuel, such as combustion of lignocellulose. Still other additional or alternate potential CO₂ sources can correspond to output or exhaust streams from various industrial processes, such as CO₂-containing streams generated by plants for manufacture of steel, cement, and/or paper.

Yet another additional or alternate potential source of CO₂ can be CO₂-containing streams from a fuel cell. The CO₂-containing stream from a fuel cell can correspond to a cathode output stream from a different fuel cell, an anode output stream from a different fuel cell, a recycle stream from the cathode output to the cathode input of a fuel cell, and/or a recycle stream from an anode output to a cathode input of a fuel cell. For example, an MCFC operated in standalone mode under conventional conditions can generate a cathode exhaust with a CO₂ concentration of at least about 5 vol %. Such a CO₂-containing cathode exhaust could be used as a cathode input for an MCFC operated according to an aspect of the invention. More generally, other types of fuel cells that generate a CO₂ output from the cathode exhaust can additionally or alternately be used, as well as other types of CO₂-containing streams not generated by a “combustion” reaction and/or by a combustion-powered generator. Optionally but preferably, a CO₂-containing stream from another fuel cell can be from another molten carbonate fuel cell. For example, for molten carbonate fuel cells connected in series with respect to the cathodes, the output from the cathode for a first molten carbonate fuel cell can be used as the input to the cathode for a second molten carbonate fuel cell.

For various types of CO₂-containing streams from sources other than combustion sources, the CO₂ content of the stream can vary widely. The CO₂ content of an input stream to a cathode can contain at least about 2 vol % of CO₂, such as at least about 4 vol %, or at least about 5 vol %, or at least about 6 vol %, or at least about 8 vol %. Additionally or alternately, the CO₂ content of an input stream to a cathode can be about 30 vol % or less, such as about 25 vol % or less, or about 20 vol % or less, or about 15 vol % or less, or about 10 vol % or less, or about 8 vol % or less, or about 6 vol % or less, or about 4 vol % or less. For some still higher CO₂ content streams, the CO₂ content can be greater than about 30 vol %, such as a stream substantially composed of CO₂ with only incidental amounts of other compounds. As an example, a gas-fired turbine without exhaust gas recycle can produce an exhaust stream with a CO₂ content of approximately 4.2 vol %. With EGR, a gas-fired turbine can produce an exhaust stream with a CO₂ content of about 6-8 vol %. Stoichiometric combustion of methane can produce an exhaust stream with a CO₂ content of about 11 vol %. Combustion of coal can produce an exhaust stream with a CO₂ content of about 15-20 vol %. Fired heaters using refinery off-gas can produce an exhaust stream with a CO₂ content of about 12-15 vol %. A gas turbine operated on a low BTU gas without any EGR can produce an exhaust stream with a CO₂ content of ˜12 vol %.

In addition to CO₂, a cathode input stream must include O₂ to provide the components necessary for the cathode reaction. Some cathode input streams can be based on having air as a component. For example, a combustion exhaust stream can be formed by combusting a hydrocarbon fuel in the presence of air. Such a combustion exhaust stream, or another type of cathode input stream having an oxygen content based on inclusion of air, can have an oxygen content of about 20 vol % or less, such as about 15 vol % or less, or about 10 vol % or less. Additionally or alternately, the oxygen content of the cathode input stream can be at least about 4 vol %, such as at least about 6 vol %, or at least about 8 vol %. More generally, a cathode input stream can have a suitable content of oxygen for performing the cathode reaction. In some aspects, this can correspond to an oxygen content of about 5 vol % to about 15 vol %, such as from about 7 vol % to about 9 vol %. For many types of cathode input streams, the combined amount of CO₂ and O₂ can correspond to less than about 21 vol % of the input stream, such as less than about 15 vol % of the stream or less than about 10 vol % of the stream. An air stream containing oxygen can be combined with a CO₂ source that has low oxygen content. For example, the exhaust stream generated by burning coal may include a low oxygen content that can be mixed with air to form a cathode inlet stream.

In addition to CO₂ and O₂, a cathode input stream can also be composed of inert/non-reactive species such as N₂, H₂O, and other typical oxidant (air) components. For example, for a cathode input derived from an exhaust from a combustion reaction, if air is used as part of the oxidant source for the combustion reaction, the exhaust gas can include typical components of air such as N₂, H₂O, and other compounds in minor amounts that are present in air. Depending on the nature of the fuel source for the combustion reaction, additional species present after combustion based on the fuel source may include one or more of H₂O, oxides of nitrogen (NOx) and/or sulfur (SOx), and other compounds either present in the fuel and/or that are partial or complete combustion products of compounds present in the fuel, such as CO. These species may be present in amounts that do not poison the cathode catalyst surfaces though they may reduce the overall cathode activity. Such reductions in performance may be acceptable, or species that interact with the cathode catalyst may be reduced to acceptable levels by known pollutant removal technologies.

The amount of O₂ present in a cathode input stream (such as an input cathode stream based on a combustion exhaust) can advantageously be sufficient to provide the oxygen needed for the cathode reaction in the fuel cell. Thus, the volume percentage of O₂ can advantageously be at least 0.5 times the amount of CO₂ in the exhaust. Optionally, as necessary, additional air can be added to the cathode input to provide sufficient oxidant for the cathode reaction. When some form of air is used as the oxidant, the amount of N₂ in the cathode exhaust can be at least about 78 vol %, e.g., at least about 88 vol %, and/or about 95 vol % or less. In some aspects, the cathode input stream can additionally or alternately contain compounds that are generally viewed as contaminants, such as H₂S or NH₃. In other aspects, the cathode input stream can be cleaned to reduce or minimize the content of such contaminants.

In addition to the reaction to form carbonate ions for transport across the electrolyte, the conditions in the cathode can also be suitable for conversion of nitrogen oxides into nitrate and/or nitrate ions. Hereinafter, only nitrate ions will be referred to for convenience. The resulting nitrate ions can also be transported across the electrolyte for reaction in the anode. NOx concentrations in a cathode input stream can typically be on the order of ppm, so this nitrate transport reaction can have a minimal impact on the amount of carbonate transported across the electrolyte. However, this method of NOx removal can be beneficial for cathode input streams based on combustion exhausts from gas turbines, as this can provide a mechanism for reducing NOx emissions. The conditions in the cathode can additionally or alternately be suitable for conversion of unburned hydrocarbons (in combination with O₂ in the cathode input stream) to typical combustion products, such as CO₂ and H₂O.

A suitable temperature for operation of an MCFC can be between about 450° C. and about 750° C., such as at least about 500° C., e.g., with an inlet temperature of about 550° C. and an outlet temperature of about 625° C. Prior to entering the cathode, heat can be added to or removed from the combustion exhaust, if desired, e.g., to provide heat for other processes, such as reforming the fuel input for the anode. For example, if the source for the cathode input stream is a combustion exhaust stream, the combustion exhaust stream may have a temperature greater than a desired temperature for the cathode inlet. In such an aspect, heat can be removed from the combustion exhaust prior to use as the cathode input stream. Alternatively, the combustion exhaust could be at very low temperature, for example after a wet gas scrubber on a coal-fired boiler, in which case the combustion exhaust can be below about 100° C. Alternatively, the combustion exhaust could be from the exhaust of a gas turbine operated in combined cycle mode, in which the gas can be cooled by raising steam to run a steam turbine for additional power generation. In this case, the gas can be below about 50° C. Heat can be added to a combustion exhaust that is cooler than desired.

Fuel Cell Arrangement

In various aspects, a configuration option for a fuel cell (such as a fuel cell array containing multiple fuel cell stacks) can be to divide the CO₂-containing stream between a plurality of fuel cells. Some types of sources for CO₂-containing streams can generate large volumetric flow rates relative to the capacity of an individual fuel cell. For example, the CO₂-containing output stream from an industrial combustion source can typically correspond to a large flow volume relative to desirable operating conditions for a single MCFC of reasonable size. Instead of processing the entire flow in a single MCFC, the flow can be divided amongst a plurality of MCFC units, usually at least some of which can be in parallel, so that the flow rate in each unit can be within a desired flow range.

A second configuration option can be to utilize fuel cells in series to successively remove CO₂ from a flow stream. Regardless of the number of initial fuel cells to which a CO₂-containing stream can be distributed to in parallel, each initial fuel cell can be followed by one or more additional cells in series to further remove additional CO₂. If the desired amount of CO₂ in the cathode output is sufficiently low, attempting to remove CO₂ from a cathode input stream down to the desired level in a single fuel cell or fuel cell stage could lead to a low and/or unpredictable voltage output for the fuel cell. Rather than attempting to remove CO₂ to the desired level in a single fuel cell or fuel cell stage, CO₂ can be removed in successive cells until a desired level can be achieved. For example, each cell in a series of fuel cells can be used to remove some percentage (e.g., about 50%) of the CO₂ present in a fuel stream. In such an example, if three fuel cells are used in series, the CO₂ concentration can be reduced (e.g., to about 15% or less of the original amount present, which can correspond to reducing the CO₂ concentration from about 6% to about 1% or less over the course of three fuel cells in series).

In another configuration, the operating conditions can be selected in early fuel stages in series to provide a desired output voltage while the array of stages can be selected to achieve a desired level of carbon separation. As an example, an array of fuel cells can be used with three fuel cells in series. The first two fuel cells in series can be used to remove CO₂ while maintaining a desired output voltage. The final fuel cell can then be operated to remove CO₂ to a desired concentration but at a lower voltage.

In still another configuration, there can be separate connectivity for the anodes and cathodes in a fuel cell array. For example, if the fuel cell array includes fuel cathodes connected in series, the corresponding anodes can be connected in any convenient manner, not necessarily matching up with the same arrangement as their corresponding cathodes, for example. This can include, for instance, connecting the anodes in parallel, so that each anode receives the same type of fuel feed, and/or connecting the anodes in a reverse series, so that the highest fuel concentration in the anodes can correspond to those cathodes having the lowest CO₂ concentration.

In yet another configuration, the amount of fuel delivered to one or more anode stages and/or the amount of CO₂ delivered to one or more cathode stages can be controlled in order to improve the performance of the fuel cell array. For example, a fuel cell array can have a plurality of cathode stages connected in series. In an array that includes three cathode stages in series, this can mean that the output from a first cathode stage can correspond to the input for a second cathode stage, and the output from the second cathode stage can correspond to the input for a third cathode stage. In this type of configuration, the CO₂ concentration can decrease with each successive cathode stage. To compensate for this reduced CO₂ concentration, additional hydrogen and/or methane can be delivered to the anode stages corresponding to the later cathode stages. The additional hydrogen and/or methane in the anodes corresponding to the later cathode stages can at least partially offset the loss of voltage and/or current caused by the reduced CO₂ concentration, which can increase the voltage and thus net power produced by the fuel cell. In another example, the cathodes in a fuel cell array can be connected partially in series and partially in parallel. In this type of example, instead of passing the entire combustion output into the cathodes in the first cathode stage, at least a portion of the combustion exhaust can be passed into a later cathode stage. This can provide an increased CO₂ content in a later cathode stage. Still other options for using variable feeds to either anode stages or cathode stages can be used if desired.

The cathode of a fuel cell can correspond to a plurality of cathodes from an array of fuel cells, as previously described. In some aspects, a fuel cell array can be operated to improve or maximize the amount of carbon transferred from the cathode to the anode. In such aspects, for the cathode output from the final cathode(s) in an array sequence (typically at least including a series arrangement, or else the final cathode(s) and the initial cathode(s) would be the same), the output composition can include about 2.0 vol % or less of CO₂ (e.g., about 1.5 vol % or less or about 1.2 vol % or less) and/or at least about 0.5 vol % of CO₂, or at least about 1.0 vol %, or at least about 1.2 vol % or at least about 1.5 vol %. Due to this limitation, the net efficiency of CO₂ removal when using molten carbonate fuel cells can be dependent on the amount of CO₂ in the cathode input. For cathode input streams with CO₂ contents of greater than about 6 vol %, such as at least about 8%, the limitation on the amount of CO₂ that can be removed is not severe. However, for a combustion reaction using natural gas as a fuel and with excess air, as is typically found in a gas turbine, the amount of CO₂ in the combustion exhaust may only correspond to a CO₂ concentration at the cathode input of less than about 5 vol %. Use of exhaust gas recycle can allow the amount of CO₂ at the cathode input to be increased to at least about 5 vol %, e.g., at least about 6 vol %. If EGR is increased when using natural gas as a fuel to produce a CO₂ concentration beyond about 6 vol %, then the flammability in the combustor can be decreased and the gas turbine may become unstable. However, when H₂ is added to the fuel, the flammability window can be significantly increased, allowing the amount of exhaust gas recycle to be increased further, so that concentrations of CO₂ at the cathode input of at least about 7.5 vol % or at least about 8 vol % can be achieved. As an example, based on a removal limit of about 1.5 vol % at the cathode exhaust, increasing the CO₂ content at the cathode input from about 5.5 vol % to about 7.5 vol % can correspond to a ˜10% increase in the amount of CO₂ that can be captured using a fuel cell and transported to the anode loop for eventual CO₂ separation. The amount of O₂ in the cathode output can additionally or alternately be reduced, typically in an amount proportional to the amount of CO₂ removed, which can result in small corresponding increases in the amount(s) of the other (non-cathode-reactive) species at the cathode exit.

In other aspects, a fuel cell array can be operated to improve or maximize the energy output of the fuel cell, such as the total energy output, the electric energy output, the syngas chemical energy output, or a combination thereof. For example, molten carbonate fuel cells can be operated with an excess of reformable fuel in a variety of situations, such as for generation of a syngas stream for use in chemical synthesis plant and/or for generation of a high purity hydrogen stream. The syngas stream and/or hydrogen stream can be used as a syngas source, a hydrogen source, as a clean fuel source, and/or for any other convenient application. In such aspects, the amount of CO₂ in the cathode exhaust can be related to the amount of CO₂ in the cathode input stream and the CO₂ utilization at the desired operating conditions for improving or maximizing the fuel cell energy output.

Additionally or alternately, depending on the operating conditions, an MCFC can lower the CO₂ content of a cathode exhaust stream to about 5.0 vol % or less, e.g., about 4.0 vol % or less, or about 2.0 vol % or less, or about 1.5 vol % or less, or about 1.2 vol % or less. Additionally or alternately, the CO₂ content of the cathode exhaust stream can be at least about 0.9 vol %, such as at least about 1.0 vol %, or at least about 1.2 vol %, or at least about 1.5 vol %.

Molten Carbonate Fuel Cell Operation

In some aspects, a fuel cell may be operated in a single pass or once-through mode. In single pass mode, reformed products in the anode exhaust are not returned to the anode inlet. Thus, recycling syngas, hydrogen, or some other product from the anode output directly to the anode inlet is not done in single pass operation. More generally, in single pass operation, reformed products in the anode exhaust are also not returned indirectly to the anode inlet, such as by using reformed products to process a fuel stream subsequently introduced into the anode inlet. Optionally, CO₂ from the anode outlet can be recycled to the cathode inlet during operation of an MCFC in single pass mode. More generally, in some alternative aspects, recycling from the anode outlet to the cathode inlet may occur for an MCFC operating in single pass mode. Heat from the anode exhaust or output may additionally or alternately be recycled in a single pass mode. For example, the anode output flow may pass through a heat exchanger that cools the anode output and warms another stream, such as an input stream for the anode and/or the cathode. Recycling heat from anode to the fuel cell is consistent with use in single pass or once-through operation. Optionally but not preferably, constituents of the anode output may be burned to provide heat to the fuel cell during single pass mode.

FIG. 3 shows a schematic example of the operation of an MCFC for generation of electrical power. In FIG. 3, the anode portion of the fuel cell can receive fuel and steam (H₂O) as inputs, with outputs of water, CO₂, and optionally excess H₂, CH₄ (or other hydrocarbons), and/or CO. The cathode portion of the fuel cell can receive CO₂ and some oxidant (e.g., air/O₂) as inputs, with an output corresponding to a reduced amount of CO₂ in O₂-depleted oxidant (air). Within the fuel cell, CO₃ ²⁻ ions formed in the cathode side can be transported across the electrolyte to provide the carbonate ions needed for the reactions occurring at the anode.

Several reactions can occur within a molten carbonate fuel cell such as the example fuel cell shown in FIG. 3. The reforming reactions can be optional, and can be reduced or eliminated if sufficient H₂ is provided directly to the anode. The following reactions are based on CH₄, but similar reactions can occur when other fuels are used in the fuel cell.

(1) <anode reforming> CH₄+H₂O=>3H₂+CO

(2) <water gas shift> CO+H₂O=>H₂+CO₂

(3) <reforming and water gas shift combined> CH₄+2H₂O=>4H₂+CO₂

(4) <anode H₂ oxidation> H₂+CO₃ ²⁻=>H₂O+CO₂+2e ⁻

(5) <cathode> ½O₂+CO₂+2e ⁻=>O₃ ²⁻

Reaction (1) represents the basic hydrocarbon reforming reaction to generate H₂ for use in the anode of the fuel cell. The CO formed in reaction (1) can be converted to H₂ by the water-gas shift reaction (2). The combination of reactions (1) and (2) is shown as reaction (3). Reactions (1) and (2) can occur external to the fuel cell, and/or the reforming can be performed internal to the anode.

Reactions (4) and (5), at the anode and cathode respectively, represent the reactions that can result in electrical power generation within the fuel cell. Reaction (4) combines H₂, either present in the feed or optionally generated by reactions (1) and/or (2), with carbonate ions to form H₂O, CO₂, and electrons to the circuit. Reaction (5) combines O₂, CO₂, and electrons from the circuit to form carbonate ions. The carbonate ions generated by reaction (5) can be transported across the electrolyte of the fuel cell to provide the carbonate ions needed for reaction (4). In combination with the transport of carbonate ions across the electrolyte, a closed current loop can then be formed by providing an electrical connection between the anode and cathode.

In various embodiments, a goal of operating the fuel cell can be to improve the total efficiency of the fuel cell and/or the total efficiency of the fuel cell plus an integrated chemical synthesis process. This is typically in contrast to conventional operation of a fuel cell, where the goal can be to operate the fuel cell with high electrical efficiency for using the fuel provided to the cell for generation of electrical power. As defined above, total fuel cell efficiency may be determined by dividing the electric output of the fuel cell plus the lower heating value of the fuel cell outputs by the lower heating value of the input components for the fuel cell. In other words, TFCE=(LHV(el)+LHV(sg out))/LHV(in), where LHV(in) and LHV(sg out) refer to the LHV of the fuel components (such as H₂, CH₄, and/or CO) delivered to the fuel cell and syngas (H₂, CO and/or CO₂) in the anode outlet streams or flows, respectively. This can provide a measure of the electric energy plus chemical energy generated by the fuel cell and/or the integrated chemical process. It is noted that under this definition of total efficiency, heat energy used within the fuel cell and/or used within the integrated fuel cell/chemical synthesis system can contribute to total efficiency. However, any excess heat exchanged or otherwise withdrawn from the fuel cell or integrated fuel cell/chemical synthesis system is excluded from the definition. Thus, if excess heat from the fuel cell is used, for example, to generate steam for electricity generation by a steam turbine, such excess heat is excluded from the definition of total efficiency.

Several operational parameters may be manipulated to operate a fuel cell with excess reformable fuel. Some parameters can be similar to those currently recommended for fuel cell operation. In some aspects, the cathode conditions and temperature inputs to the fuel cell can be similar to those recommended in the literature. For example, the desired electrical efficiency and the desired total fuel cell efficiency may be achieved at a range of fuel cell operating temperatures typical for molten carbonate fuel cells. In typical operation, the temperature can increase across the fuel cell.

In other aspects, the operational parameters of the fuel cell can deviate from typical conditions so that the fuel cell is operated to allow a temperature decrease from the anode inlet to the anode outlet and/or from the cathode inlet to the cathode outlet. For example, the reforming reaction to convert a hydrocarbon into H₂ and CO is an endothermic reaction. If a sufficient amount of reforming is performed in a fuel cell anode relative to the amount of oxidation of hydrogen to generate electrical current, the net heat balance in the fuel cell can be endothermic. This can cause a temperature drop between the inlets and outlets of a fuel cell. During endothermic operation, the temperature drop in the fuel cell can be controlled so that the electrolyte in the fuel cell remains in a molten state.

Parameters that can be manipulated in a way so as to differ from those currently recommended can include the amount of fuel provided to the anode, the composition of the fuel provided to the anode, and/or the separation and capture of syngas in the anode output without significant recycling of syngas from the anode exhaust to either the anode input or the cathode input. In some aspects, no recycle of syngas or hydrogen from the anode exhaust to either the anode input or the cathode input can be allowed to occur, either directly or indirectly. In additional or alternative aspects, a limited amount of recycle can occur. In such aspects, the amount of recycle from the anode exhaust to the anode input and/or the cathode input can be less than about 10 vol % of the anode exhaust, such as less than about 5 vol %, or less than about 1 vol %.

Additionally or alternately, a goal of operating a fuel cell can be to separate CO₂ from the output stream of a combustion reaction or another process that produces a CO₂ output stream, in addition to allowing generation of electric power. In such aspects, the combustion reaction(s) can be used to power one or more generators or turbines, which can provide a majority of the power generated by the combined generator/fuel cell system. Rather than operating the fuel cell to optimize power generation by the fuel cell, the system can instead be operated to improve the capture of carbon dioxide from the combustion-powered generator while reducing or minimizing the number of fuels cells required for capturing the carbon dioxide. Selecting an appropriate configuration for the input and output flows of the fuel cell, as well as selecting appropriate operating conditions for the fuel cell, can allow for a desirable combination of total efficiency and carbon capture.

In some embodiments, the fuel cells in a fuel cell array can be arranged so that only a single stage of fuel cells (such as fuel cell stacks) can be present. In this type of embodiment, the anode fuel utilization for the single stage can represent the anode fuel utilization for the array. Another option can be that a fuel cell array can contain multiple stages of anodes and multiple stages of cathodes, with each anode stage having a fuel utilization within the same range, such as each anode stage having a fuel utilization within 10% of a specified value, for example within 5% of a specified value. Still another option can be that each anode stage can have a fuel utilization equal to a specified value or lower than the specified value by less than an amount, such as having each anode stage be not greater than a specified value by 10% or less, for example, by 5% or less. As an illustrative example, a fuel cell array with a plurality of anode stages can have each anode stage be within about 10% of 50% fuel utilization, which would correspond to each anode stage having a fuel utilization between about 40% and about 60%. As another example, a fuel cell array with a plurality of stages can have each anode stage be not greater than 60% anode fuel utilization with the maximum deviation being about 5% less, which would correspond to each anode stage having a fuel utilization between about 55% to about 60%. In still another example, one or more stages of fuel cells in a fuel cell array can be operated at a fuel utilization from about 30% to about 50%, such as operating a plurality of fuel cell stages in the array at a fuel utilization from about 30% to about 50%. More generally, any of the above types of ranges can be paired with any of the anode fuel utilization values specified herein.

Still another additional or alternate option can include specifying a fuel utilization for less than all of the anode stages. For example, in some aspects of the invention fuel cells/stacks can be arranged at least partially in one or more series arrangements such that anode fuel utilization can be specified for the first anode stage in a series, the second anode stage in a series, the final anode stage in a series, or any other convenient anode stage in a series. As used herein, the “first” stage in a series corresponds to the stage (or set of stages, if the arrangement contains parallel stages as well) to which input is directly fed from the fuel source(s), with later (“second,” “third,” “final,” etc.) stages representing the stages to which the output from one or more previous stages is fed, instead of directly from the respective fuel source(s). In situations where both output from previous stages and input directly from the fuel source(s) are co-fed into a stage, there can be a “first” (set of) stage(s) and a “last” (set of) stage(s), but other stages (“second,” “third,” etc.) can be more tricky among which to establish an order (e.g., in such cases, ordinal order can be determined by concentration levels of one or more components in the composite input feed composition, such as CO₂ for instance, from highest concentration “first” to lowest concentration “last” with approximately similar compositional distinctions representing the same ordinal level.)

Yet another additional or alternate option can be to specify the anode fuel utilization corresponding to a particular cathode stage (again, where fuel cells/stacks can be arranged at least partially in one or more series arrangements). As noted above, based on the direction of the flows within the anodes and cathodes, the first cathode stage may not correspond to (be across the same fuel cell membrane from) the first anode stage. Thus, in some aspects of the invention, the anode fuel utilization can be specified for the first cathode stage in a series, the second cathode stage in a series, the final cathode stage in a series, or any other convenient cathode stage in a series.

Yet still another additional or alternate option can be to specify an overall average of fuel utilization over all fuel cells in a fuel cell array. In various aspects, the overall average of fuel utilization for a fuel cell array can be about 65% or less, for example, about 60% or less, about 55% or less, about 50% or less, or about 45% or less (additionally or alternately, the overall average fuel utilization for a fuel cell array can be at least about 25%, for example at least about 30%, at least about 35%, or at least about 40%). Such an average fuel utilization need not necessarily constrain the fuel utilization in any single stage, so long as the array of fuel cells meets the desired fuel utilization.

Applications for CO₂ Output after Capture

In various aspects of the invention, the systems and methods described above can allow for production of carbon dioxide as a pressurized fluid. For example, the CO₂ generated from a cryogenic separation stage can initially correspond to a pressurized CO₂ liquid with a purity of at least about 90%, e.g., at least about 95%, at least about 97%, at least about 98%, or at least about 99%. This pressurized CO₂ stream can be used, e.g., for injection into wells in order to further enhance oil or gas recovery such as in secondary oil recovery. When done in proximity to a facility that encompasses a gas turbine, the overall system may benefit from additional synergies in use of electrical/mechanical power and/or through heat integration with the overall system.

Alternatively, for systems dedicated to an enhanced oil recovery (EOR) application (i.e., not comingled in a pipeline system with tight compositional standards), the CO₂ separation requirements may be substantially relaxed. The EOR application can be sensitive to the presence of O₂, so O₂ can be absent, in some embodiments, from a CO₂ stream intended for use in EOR. However, the EOR application can tend to have a low sensitivity to dissolved CO, H₂, and/or CH₄. Also, pipelines that transport the CO₂ can be sensitive to these impurities. Those dissolved gases can typically have only subtle impacts on the solubilizing ability of CO₂ used for EOR. Injecting gases such as CO, H₂, and/or CH₄ as EOR gases can result in some loss of fuel value recovery, but such gases can be otherwise compatible with EOR applications.

Additionally or alternately, a potential use for CO₂ as a pressurized liquid can be as a nutrient in biological processes such as algae growth/harvesting. The use of MCFCs for CO₂ separation can ensure that most biologically significant pollutants could be reduced to acceptably low levels, resulting in a CO₂-containing stream having only minor amounts of other “contaminant” gases (such as CO, H₂, N₂, and the like, and combinations thereof) that are unlikely to substantially negatively affect the growth of photosynthetic organisms. This can be in stark contrast to the output streams generated by most industrial sources, which can often contain potentially highly toxic material such as heavy metals.

In this type of aspect of the invention, the CO₂ stream generated by separation of CO₂ in the anode loop can be used to produce biofuels and/or chemicals, as well as precursors thereof. Further additionally or alternately, CO₂ may be produced as a dense fluid, allowing for much easier pumping and transport across distances, e.g., to large fields of photosynthetic organisms. Conventional emission sources can emit hot gas containing modest amounts of CO₂ (e.g., about 4-15%) mixed with other gases and pollutants. These materials would normally need to be pumped as a dilute gas to an algae pond or biofuel “farm”. By contrast, the MCFC system according to the invention can produce a concentrated CO₂ stream (˜60-70% by volume on a dry basis) that can be concentrated further to 95%+ (for example 96%+, 97%+, 98%+, or 99%+) and easily liquefied. This stream can then be transported easily and efficiently over long distances at relatively low cost and effectively distributed over a wide area. In these embodiments, residual heat from the combustion source/MCFC may be integrated into the overall system as well.

An alternative embodiment may apply where the CO₂ source/MCFC and biological/chemical production sites are co-located. In that case, only minimal compression may be necessary (i.e., to provide enough CO₂ pressure to use in the biological production, e.g., from about 15 psig to about 150 psig). Several novel arrangements can be possible in such a case. Secondary reforming may optionally be applied to the anode exhaust to reduce CH₄ content, and water-gas shift may optionally additionally or alternately be present to drive any remaining CO into CO₂ and H₂.

The components from an anode output stream and/or cathode output stream can be used for a variety of purposes. One option can be to use the anode output as a source of hydrogen, as described above. For an MCFC integrated with or co-located with a refinery, the hydrogen can be used as a hydrogen source for various refinery processes, such as hydroprocessing. Another option can be to additionally or alternately use hydrogen as a fuel source where the CO₂ from combustion has already been “captured.” Such hydrogen can be used in a refinery or other industrial setting as a fuel for a boiler, furnace, and/or fired heater, and/or the hydrogen can be used as a feed for an electric power generator, such as a turbine. Hydrogen from an MCFC fuel cell can further additionally or alternately be used as an input stream for other types of fuel cells that require hydrogen as an input, possibly including vehicles powered by fuel cells. Still another option can be to additionally or alternately use syngas generated as an output from an MCFC fuel cell as a fermentation input.

Another option can be to additionally or alternately use syngas generated from the anode output. Of course, syngas can be used as a fuel, although a syngas based fuel can still lead to some CO₂ production when burned as fuel. In other aspects, a syngas output stream can be used as an input for a chemical synthesis process. One option can be to additionally or alternately use syngas for a Fischer-Tropsch type process, and/or another process where larger hydrocarbon molecules are formed from the syngas input. Another option can be to additionally or alternately use syngas to form an intermediate product such as methanol. Methanol could be used as the final product, but in other aspects methanol generated from syngas can be used to generate larger compounds, such as gasoline, olefins, aromatics, and/or other products. It is noted that a small amount of CO₂ can be acceptable in the syngas feed to a methanol synthesis process, and/or to a Fischer-Tropsch process utilizing a shifting catalyst. Hydroformylation is an additional or alternate example of still another synthesis process that can make use of a syngas input.

It is noted that one variation on use of an MCFC to generate syngas can be to use MCFC fuel cells as part of a system for processing methane and/or natural gas withdrawn by an offshore oil platform or other production system that is a considerable distance from its ultimate market. Instead of attempting to transport the gas phase output from a well, or attempting to store the gas phase product for an extended period, the gas phase output from a well can be used as the input to an MCFC fuel cell array. This can lead to a variety of benefits. First, the electric power generated by the fuel cell array can be used as a power source for the platform. Additionally, the syngas output from the fuel cell array can be used as an input for a Fischer-Tropsch process at the production site. This can allow for formation of liquid hydrocarbon products more easily transported by pipeline, ship, or railcar from the production site to, for example, an on-shore facility or a larger terminal.

Still other integration options can additionally or alternately include using the cathode output as a source of higher purity, heated nitrogen. The cathode input can often include a large portion of air, which means a substantial portion of nitrogen can be included in the cathode input. The fuel cell can transport CO₂ and O₂ from the cathode across the electrolyte to the anode, and the cathode outlet can have lower concentrations of CO₂ and O₂, and thus a higher concentration of N₂ than found in air. With subsequent removal of the residual O₂ and CO₂, this nitrogen output can be used as an input for production of ammonia or other nitrogen-containing chemicals, such as urea, ammonium nitrate, and/or nitric acid. It is noted that urea synthesis could additionally or alternately use CO₂ separate from the anode output as an input feed.

Integration Example: Applications for Integration with Combustion Turbines

In some aspects of the invention, a combustion source for generating power and exhausting a CO₂-containing exhaust can be integrated with the operation of molten carbonate fuel cells. An example of a suitable combustion source is a gas turbine. Preferably, the gas turbine can combust natural gas, methane gas, or another hydrocarbon gas in a combined cycle mode integrated with steam generation and heat recovery for additional efficiency. Modern natural gas combined cycle efficiencies are about 60% for the largest and newest designs. The resulting CO₂-containing exhaust gas stream can be produced at an elevated temperature compatible with the MCFC operation, such as 300° C.-700° C. and preferably 500° C.-650° C. The gas source can optionally but preferably be cleaned of contaminants such as sulfur that can poison the MCFC before entering the turbine. Alternatively, the gas source can be a coal-fired generator, wherein the exhaust gas would typically be cleaned post-combustion due to the greater level of contaminants in the exhaust gas. In such an alternative, some heat exchange to/from the gas may be necessary to enable clean-up at lower temperatures. In additional or alternate embodiments, the source of the CO₂-containing exhaust gas can be the output from a boiler, combustor, or other heat source that burns carbon-rich fuels. In other additional or alternate embodiments, the source of the CO₂-containing exhaust gas can be bio-produced CO₂ in combination with other sources.

For integration with a combustion source, some alternative configurations for processing of a fuel cell anode can be desirable. For example, an alternative configuration can be to recycle at least a portion of the exhaust from a fuel cell anode to the input of a fuel cell anode. The output stream from an MCFC anode can include H₂O, CO₂, optionally CO, and optionally but typically unreacted fuel (such as H₂ or CH₄) as the primary output components. Instead of using this output stream as an external fuel stream and/or an input stream for integration with another process, one or more separations can be performed on the anode output stream in order to separate the CO₂ from the components with potential fuel value, such as H₂ or CO. The components with fuel value can then be recycled to the input of an anode.

This type of configuration can provide one or more benefits. First, CO₂ can be separated from the anode output, such as by using a cryogenic CO₂ separator. Several of the components of the anode output (H₂, CO, CH₄) are not easily condensable components, while CO₂ and H₂O can be separated individually as condensed phases. Depending on the embodiment, at least about 90 vol % of the CO₂ in the anode output can be separated to form a relatively high purity CO₂ output stream. Alternatively, in some aspects less CO₂ can be removed from the anode output, so that about 50 vol % to about 90 vol % of the CO₂ in the anode output can be separated out, such as about 80 vol % or less or about 70 vol % or less. After separation, the remaining portion of the anode output can correspond primarily to components with fuel value, as well as reduced amounts of CO₂ and/or H₂O. This portion of the anode output after separation can be recycled for use as part of the anode input, along with additional fuel. In this type of configuration, even though the fuel utilization in a single pass through the MCFC(s) may be low, the unused fuel can be advantageously recycled for another pass through the anode. As a result, the single-pass fuel utilization can be at a reduced level, while avoiding loss (exhaust) of unburned fuel to the environment.

Additionally or alternatively to recycling a portion of the anode exhaust to the anode input, another configuration option can be to use a portion of the anode exhaust as an input for a combustion reaction for a turbine or other combustion device, such as a boiler, furnace, and/or fired heater. The relative amounts of anode exhaust recycled to the anode input and/or as an input to the combustion device can be any convenient or desirable amount. If the anode exhaust is recycled to only one of the anode input and the combustion device, the amount of recycle can be any convenient amount, such as up to 100% of the portion of the anode exhaust remaining after any separation to remove CO₂ and/or H₂O. When a portion of the anode exhaust is recycled to both the anode input and the combustion device, the total recycled amount by definition can be 100% or less of the remaining portion of anode exhaust. Otherwise, any convenient split of the anode exhaust can be used. In various embodiments of the invention, the amount of recycle to the anode input can be at least about 10% of the anode exhaust remaining after separations, for example at least about 25%, at least about 40%, at least about 50%, at least about 60%, at least about 75%, or at least about 90%. Additionally or alternately in those embodiments, the amount of recycle to the anode input can be about 90% or less of the anode exhaust remaining after separations, for example about 75% or less, about 60% or less, about 50% or less, about 40% or less, about 25% or less, or about 10% or less. Further additionally or alternately, in various embodiments of the invention, the amount of recycle to the combustion device can be at least about 10% of the anode exhaust remaining after separations, for example at least about 25%, at least about 40%, at least about 50%, at least about 60%, at least about 75%, or at least about 90%. Additionally or alternately in those embodiments, the amount of recycle to the combustion device can be about 90% or less of the anode exhaust remaining after separations, for example about 75% or less, about 60% or less, about 50% or less, about 40% or less, about 25% or less, or about 10% or less.

In still other alternative aspects of the invention, the fuel for a combustion device can additionally or alternately be a fuel with an elevated quantity of components that are inert and/or otherwise act as a diluent in the fuel. CO₂ and N₂ are examples of components in a natural gas feed that can be relatively inert during a combustion reaction. When the amount of inert components in a fuel feed reaches a sufficient level, the performance of a turbine or other combustion source can be impacted. The impact can be due in part to the ability of the inert components to absorb heat, which can tend to quench the combustion reaction. Examples of fuel feeds with a sufficient level of inert components can include fuel feeds containing at least about 20 vol % CO₂, or fuel feeds containing at least about 40 vol % N₂, or fuel feeds containing combinations of CO₂ and N₂ that have sufficient inert heat capacity to provide similar quenching ability. (It is noted that CO₂ has a greater heat capacity than N₂, and therefore lower concentrations of CO₂ can have a similar impact as higher concentrations of N₂. CO₂ can also participate in the combustion reactions more readily than N₂, and in doing so remove H₂ from the combustion. This consumption of H₂ can have a large impact on the combustion of the fuel, by reducing the flame speed and narrowing the flammability range of the air and fuel mixture.) More generally, for a fuel feed containing inert components that impact the flammability of the fuel feed, the inert components in the fuel feed can be at least about 20 vol %, such as at least about 40 vol %, or at least about 50 vol %, or at least about 60 vol %. Preferably, the amount of inert components in the fuel feed can be about 80 vol % or less.

When a sufficient amount of inert components are present in a fuel feed, the resulting fuel feed can be outside of the flammability window for the fuel components of the feed. In this type of situation, addition of H₂ from a recycled portion of the anode exhaust to the combustion zone for the generator can expand the flammability window for the combination of fuel feed and H₂, which can allow, for example, a fuel feed containing at least about 20 vol % CO₂ or at least about 40% N₂ (or other combinations of CO₂ and N₂) to be successfully combusted.

Relative to a total volume of fuel feed and H₂ delivered to a combustion zone, the amount of H₂ for expanding the flammability window can be at least about 5 vol % of the total volume of fuel feed plus H₂, such as at least about 10 vol %, and/or about 25 vol % or less. Another option for characterizing the amount of H₂ to add to expand the flammability window can be based on the amount of fuel components present in the fuel feed before H₂ addition. Fuel components can correspond to methane, natural gas, other hydrocarbons, and/or other components conventionally viewed as fuel for a combustion-powered turbine or other generator. The amount of H₂ added to the fuel feed can correspond to at least about one third of the volume of fuel components (1:3 ratio of H₂:fuel component) in the fuel feed, such as at least about half of the volume of the fuel components (1:2 ratio). Additionally or alternately, the amount of H₂ added to the fuel feed can be roughly equal to the volume of fuel components in the fuel feed (1:1 ratio) or less. For example, for a feed containing about 30 vol % CH₄, about 10% N₂, and about 60% CO₂, a sufficient amount of anode exhaust can be added to the fuel feed to achieve about a 1:2 ratio of H₂ to CH₄. For an idealized anode exhaust that contained only H₂, addition of H₂ to achieve a 1:2 ratio would result in a feed containing about 26 vol % CH₄, 13 vol % H₂, 9 vol % N₂, and 52 vol % CO₂.

Example of Integrated System

FIG. 4 schematically shows an example of an integrated serial turbine system with an molten carbonate fuel cell. The system including introduction of both CO₂-containing recycled exhaust gas and H₂ or CO from the fuel cell anode exhaust into the combustion reaction for powering a turbine. The serial turbine system 402 includes two or more turbines arranged in series where exhaust gas from an upstream turbine is introduced in the combustion chamber of a downstream turbine, optionally, but preferably via the downstream turbine's compression section. The serial turbine system is described in more detail herein, including with reference to FIG. 5. The serial turbine system generates a final exhaust gas 422 comprising, at least, CO₂. In contrast to the system 500 shown in FIG. 5, the HRSG 560 may optionally be removed from the system when the exhaust 422 is introduced into a fuel cell to take advantage of the elevated temperature of the exhaust. Alternatively, the exhaust 422 may be heated after leaving the HRSG 560 and before entering the fuel array 425.

The CO₂-containing stream 422 can be passed into a cathode portion (not shown) of a molten carbonate fuel cell array 425. Based on the reactions within fuel cell array 425, CO₂ can be separated from stream 422 and transported to the anode portion (not shown) of the fuel cell array 425. This can result in a cathode output stream 424 depleted in CO₂. The cathode output stream 424 can then be passed into a heat recovery (and optional steam generator) system 450 for generation of heat exchange and/or additional generation of electricity using steam turbines 454 (which may optionally be the same as the aforementioned steam turbines 494). After passing through heat recovery and steam generator system 450, the resulting flue gas stream 456 can be exhausted to the environment and/or passed through another type of carbon capture technology, such as an amine scrubber.

After transport of CO₂ from the cathode side to the anode side of fuel cell array 425, the anode output 435 can optionally be passed into a water gas shift reactor 470. Water gas shift reactor 470 can be used to generate additional H₂ and CO₂ at the expense of CO (and H₂O) present in the anode output 435. The output from the optional water gas shift reactor 470 can then be passed into one or more separation stages 440, such as a cold box or a cryogenic separator. This can allow for separation of an H₂O stream 447 and CO₂ stream 449 from the remaining portion of the anode output. The remaining portion of the anode output 485 can include unreacted H₂ generated by reforming but not consumed in fuel cell array 425. A first portion 445 of the H₂-containing stream 485 can be recycled to the input for the anode(s) in fuel cell array 425. A second portion 487 of stream 485 can be used as an input for combustion zone of either the first or the second turbine in the serial turbine system 402. A third portion 465 can be used as is for another purpose and/or treated for subsequent further use. Although FIG. 4 and the description herein schematically details up to three portions, it is contemplated that only one of these three portions can be exploited, only two can be exploited, or all three can be exploited according to the invention.

In various embodiments of the invention, the process can be approached as starting with a combustion reaction for powering a turbine, an internal combustion engine, or another system where heat and/or pressure generated by a combustion reaction can be converted into another form of power. The fuel for the combustion reaction can comprise or be hydrogen, a hydrocarbon, and/or any other compound containing carbon that can be oxidized (combusted) to release energy. Except for when the fuel contains only hydrogen, the composition of the exhaust gas from the combustion reaction can have a range of CO₂ contents, depending on the nature of the reaction (e.g., from at least about 2 vol % to about 25 vol % or less). Thus, in certain embodiments where the fuel is carbonaceous, the CO₂ content of the exhaust gas can be at least about 2 vol %, for example at least about 4 vol %, at least about 5 vol %, at least about 6 vol %, at least about 8 vol %, or at least about 10 vol %. Additionally or alternately in such carbonaceous fuel embodiments, the CO₂ content can be about 25 vol % or less, for example about 20 vol % or less, about 15 vol % or less, about 10 vol % or less, about 7 vol % or less, or about 5 vol % or less. Exhaust gases with lower relative CO₂ contents (for carbonaceous fuels) can correspond to exhaust gases from combustion reactions on fuels such as natural gas with lean (excess air) combustion. Higher relative CO₂ content exhaust gases (for carbonaceous fuels) can correspond to optimized natural gas combustion reactions, such as those with exhaust gas recycle, and/or combustion of fuels such as coal.

In some aspects of the invention, the fuel for the combustion reaction can contain at least about 90 vol % of compounds containing five carbons or less, e.g., at least about 95 vol %. In such aspects, the CO₂ content of the exhaust gas can be at least about 4 vol %, for example at least about 5 vol %, at least about 6 vol %, at least about 7 vol %, or at least about 7.5 vol %. Additionally or alternately, the CO₂ content of the exhaust gas can be about 13 vol % or less, e.g., about 12 vol % or less, about 10 vol % or less, about 9 vol % or less, about 8 vol % or less, about 7 vol % or less, or about 6 vol % or less. The CO₂ content of the exhaust gas can represent a range of values depending on the configuration of the combustion-powered generator. Recycle of an exhaust gas can be beneficial for achieving a CO₂ content of at least about 6 vol %, while addition of hydrogen to the combustion reaction can allow for further increases in CO₂ content to achieve a CO₂ content of at least about 7.5 vol %.

ADDITIONAL EMBODIMENTS Embodiment 1

A method for producing electricity, the method comprising: introducing a first oxygen stream and a first combustion fuel stream into a combustion chamber of a first combustion turbine; generating electricity and a first exhaust gas by combusting the first combustion fuel stream in the first combustion turbine, the first exhaust gas having first exhaust concentration of O₂ and a first exhaust concentration of CO₂; introducing at least about 50 mol % of the O₂ and at least about 50 mol % of the CO₂ from the first exhaust gas into a combustion chamber of a second combustion turbine; introducing a second combustion fuel stream into the combustion chamber of the second combustion turbine; generating electricity and a second exhaust gas by combusting the second combustion fuel stream in the second combustion turbine, the second exhaust gas having second exhaust concentration of O₂ and a second exhaust concentration of CO₂, a ratio of the second exhaust concentration of CO₂ to the first exhaust concentration of CO₂ being at least about 1.3:1; and separating CO₂ from at least a portion of the second exhaust gas, wherein, optionally, at least about 60 mol % of the O₂, at least about 70 mol % of the O₂, or at least about 80 mol % of the O₂ from the first exhaust gas can be introduced to the combustion chamber of the second combustion turbine, and wherein, optionally, at least about 60 mol % of the CO₂, at least about 70 mol % of the CO₂, or at least about 80 mol % of the CO₂ from the first exhaust gas can be introduced to the combustion chamber of the second combustion turbine.

Embodiment 2

The method of Embodiment 1, wherein the first exhaust gas has a mole fraction of CO₂ of at least about 3%, or at least about 4%, or at least about 5%, and optionally less than about 10%.

Embodiment 3

The method of Embodiment 1 or 2, wherein the second exhaust gas has a mole fraction of CO₂ of at least about 6%, or at least about 7%, or at least about 8%, and optionally less than about 20%.

Embodiment 4

The method of any one of the previous Embodiments, wherein the method further comprises introducing the first exhaust gas into a heat recovery and steam generator prior to said introducing of at least a portion of the exhaust gas into the second combustion turbine.

Embodiment 5

The method of any of the above Embodiments, wherein the method further comprises adding air to the first exhaust gas prior to said introducing of the at least about 50 mol % of the O₂ and the at least about 50 mol % of the CO₂ from the first exhaust gas into the combustion chamber of the second combustion turbine.

Embodiment 6

The method of any of the above Embodiments, wherein a ratio of the second exhaust concentration of CO₂ to the first exhaust concentration of CO₂ is at least about 1.4:1, for example at least about 1.5:1, at least about 1.6:1, at least about 1.7:1, or at least about 1.8:1, and/or optionally about 2.0:1 or less.

Embodiment 7

The method of any of the above Embodiments, wherein the first exhaust concentration of O₂ is about 15 mol % or less, for example about 14 mol % or less, about 12 mol % or less, or about 10 mol % or less, and the second exhaust concentration of O₂ is about 7 mol % or less, for example about 6 mol % or less or about 5 mol % or less.

Embodiment 8

The method of any of the above Embodiments, wherein separating CO₂ from at least a portion of the second exhaust gas comprises: introducing the at least a portion of the second exhaust gas into a cathode of a molten carbonate fuel cell; introducing an anode fuel stream comprising a reformable fuel into an anode of the molten carbonate fuel cell, an internal reforming element associated with the anode, or a combination thereof; generating electricity within the molten carbonate fuel cell; and generating an anode exhaust from the molten carbonate fuel cell comprising H₂, CO, and CO₂.

Embodiment 9

The method of Embodiment 8, further comprising performing a water gas shift process on at least a portion of the anode exhaust.

Embodiment 10

The method of Embodiment 8 or 9, further comprising separating CO₂ from at least a portion of the anode exhaust.

Embodiment 11

The method of any one of Embodiments 8-10, wherein the first combustion fuel stream, the second combustion fuel stream, the anode fuel stream comprising a reformable fuel, or a combination thereof comprises at least about 10 vol % CO₂.

Embodiment 12

The method of any one of Embodiments 8-11, further comprising forming an H₂-containing stream from at least a portion of the anode exhaust.

Embodiment 13

The method of any one of Embodiments 8-12, wherein methane comprises at least about 90 vol % of the first combustion fuel stream, the second combustion fuel stream, the anode fuel stream comprising a reformable fuel, or a combination thereof

Embodiment 14

The method of any one of Embodiments 8-13, wherein the fuel cell is operated at a thermal ratio of about 0.25 to about 1.3, optionally of about 1.0 or less or of about 0.9 or less.

Embodiment 15

The method of any one of Embodiments 8-14, wherein an amount of the reformable fuel introduced into the anode, the internal reforming element associated with the anode, or the combination thereof, is at least about 75% greater than the amount of hydrogen reacted in the molten carbonate fuel cell to generate electricity, or at least about 100% greater.

Embodiment 16

The method of any one of Embodiments 8-15, wherein the fuel cell is operated to generate electrical power at a current density of at least about 150 mA/cm² and at least about 40 mW/cm² of waste heat, the method further comprising performing an effective amount of an endothermic reaction to maintain a temperature differential between the anode inlet and an anode outlet of about 100° C. or less.

Embodiment 17

The method of any of Embodiments 8-16, wherein an electrical efficiency for the fuel cell is between about 10% and about 40% and a total fuel cell efficiency for the fuel cell is at least about 55%, for example at least about 65% or at least about 75%.

Embodiment 18

The method of any one of the previous embodiments, wherein at least about 90 mol % of the CO₂ from the first exhaust gas is introduced into the combustion chamber of the second combustion turbine, for example at least about 95 mol % or at least about 99 mol %.

Embodiment 19

The method of any one of the previous embodiments, wherein a remaining portion of the O₂ and the CO₂ from the first exhaust gas is recycled to the combustion zone of the first combustion turbine. 

What is claimed is:
 1. A method for producing electricity, the method comprising: introducing a first oxygen stream and a first combustion fuel stream into a combustion chamber of a first combustion turbine; generating electricity and a first exhaust gas by combusting the first combustion fuel stream in the first combustion turbine, the first exhaust gas having first exhaust concentration of O₂ and a first exhaust concentration of CO₂; introducing at least about 50 mol % of the O₂ and at least about 50 mol % of the CO₂ from the first exhaust gas into a combustion chamber of a second combustion turbine; introducing a second combustion fuel stream into the combustion chamber of the second combustion turbine; generating electricity and a second exhaust gas by combusting the second combustion fuel stream in the second combustion turbine, the second exhaust gas having second exhaust concentration of O₂ and a second exhaust concentration of CO₂, a ratio of the second exhaust concentration of CO₂ to the first exhaust concentration of CO₂ being at least about 1.3:1; and separating CO₂ from at least a portion of the second exhaust gas.
 2. The method of claim 1, wherein the first exhaust gas has a mole fraction of CO₂ of at least about 3%.
 3. The method of claim 1, wherein the second exhaust gas has a mole fraction of CO₂ of at least about 6%.
 4. The method of claim 1, wherein the method further comprises introducing the first exhaust gas into a heat recovery and steam generator prior to said introducing of at least a portion of the exhaust gas into the second combustion turbine.
 5. The method of claim 1, wherein the method further comprises adding air to the first exhaust gas prior to said introducing of the at least about 50 mol % of the O₂ and the at least about 50 mol % of the CO₂ from the first exhaust gas into the combustion chamber of the second combustion turbine.
 6. The method of claim 1, wherein a ratio of the second exhaust concentration of CO₂ to the first exhaust concentration of CO₂ is at least about 1.7:1.
 7. The method of claim 1, wherein the first exhaust concentration of O₂ is less than about 15 mol % and the second exhaust concentration of O₂ is less than about 7 mol %.
 8. The method of claim 1, wherein separating CO₂ from at least a portion of the second exhaust gas comprises: introducing the at least a portion of the second exhaust gas into a cathode of a molten carbonate fuel cell; introducing an anode fuel stream comprising a reformable fuel into an anode of the molten carbonate fuel cell, an internal reforming element associated with the anode, or a combination thereof; generating electricity within the molten carbonate fuel cell; and generating an anode exhaust from the molten carbonate fuel cell comprising H₂, CO, and CO₂.
 9. The method of claim 8, further comprising performing a water gas shift process on at least a portion of the anode exhaust.
 10. The method of claim 8, further comprising separating CO₂ from at least a portion of the anode exhaust.
 11. The method of claim 8, wherein one or more of the first combustion fuel stream, the second combustion fuel stream, and the anode fuel stream comprising a reformable fuel, each comprise at least about 10 vol % CO₂.
 12. The method of claim 8, further comprising forming an H₂-containing stream from at least a portion of the anode exhaust.
 13. The method of claim 8, wherein methane comprises at least about 90 vol % of the first combustion fuel stream, the second combustion fuel stream, the anode fuel stream comprising a reformable fuel, or a combination thereof.
 14. The method of claim 8, wherein the fuel cell is operated at a thermal ratio of about 0.25 to about 1.0.
 15. The method of claim 8, wherein an amount of the reformable fuel introduced into the anode, the reforming stage associated with the anode, or the combination thereof, is at least about 75% greater than an amount of hydrogen reacted in the molten carbonate fuel cell to generate electricity.
 16. The method of claim 8, wherein the fuel cell is operated to generate electrical power at a current density of at least about 150 mA/cm² and at least about 40 mW/cm² of waste heat, the method further comprising performing an effective amount of an endothermic reaction to maintain a temperature differential between the anode inlet and an anode outlet of about 100° C. or less.
 17. The method of claim 8, wherein an electrical efficiency for the fuel cell is between about 10% and about 40% and a total fuel cell efficiency for the fuel cell is at least about 55%.
 18. The method of claim 1, wherein at least about 90 mol % of the CO₂ from the first exhaust gas is introduced into the combustion chamber of the second combustion turbine.
 19. The method of claim 1, wherein at least about 99 mol % of the CO₂ from the first exhaust gas is introduced into the combustion chamber of the second combustion turbine.
 20. The method of claim 1, wherein a remaining portion of the O₂ and the CO₂ from the first exhaust gas is recycled to the combustion zone of the first combustion turbine. 